TRANSMISSION LINE SYSTEM ENVIRONMENTAL STRESSES TUTORIALS

Most environmental stress is caused by weather and by the surrounding environment, such as industry, sea, or dust in rural areas. The environmental stresses affect both mechanical and electrical performance of the line.

Temperature
The temperature in an outdoor station or line may fluctuate between –50°C and +50°C, depending upon the climate. The temperature change has no effect on the electrical performance of outdoor insulation. It is believed that high temperatures may accelerate aging. Temperature fluctuation causes an increase of mechanical stresses, however it is negligible when well-designed insulators are used.

UV Radiation
UV radiation accelerates the aging of nonceramic composite insulators, but has no effect on porcelain and glass insulators. Manufacturers use fillers and modified chemical structures of the insulating material to minimize the UV sensitivity.

Rain
Rain wets porcelain insulator surfaces and produces a thin conducting layer most of the time. This reduces the flashover voltage of the insulators. As an example, a 230-kV line may use an insulator string with 12 standard ball-and-socket-type insulators.

Dry flashover voltage of this string is 665 kV and the wet flashover voltage is 502 kV. The percentage reduction is about 25%.

Nonceramic polymer insulators have a water-repellent hydrophobic surface that reduces the effects of rain. As an example, with a 230-kV composite insulator, dry flashover voltage is 735 kV and wet flashover voltage is 630 kV.

The percentage reduction is about 15%. The insulator’s wet flashover voltage must be higher than the maximum temporary overvoltage.

Icing
In industrialized areas, conducting water may form ice due to water-dissolved industrial pollution. An example is the ice formed from acid rain water. Ice deposits form bridges across the gaps in an insulator string that result in a solid surface.

When the sun melts the ice, a conducting water layer will bridge the insulator and cause flashover at low voltages. Melting ice-caused flashover has been reported in the Quebec and Montreal areas.

Pollution
Wind drives contaminant particles into insulators. Insulators produce turbulence in airflow, which results in the deposition of particles on their surfaces. The continuous depositing of the particles increases the thickness of these deposits.

However, the natural cleaning effect of wind, which blows loose particles away, limits the growth of deposits. Occasionally, rain washes part of the pollution away. The continuous depositing and cleaning produces a seasonal variation of the pollution on the insulator surfaces.
However, after a long time (months, years), the deposits are stabilized and a thin layer of solid deposit will cover the insulator.

Because of the cleaning effects of rain, deposits are lighter on the top of the insulators and heavier on the bottom. The development of a continuous pollution layer is compounded by chemical changes.

As an example, in the vicinity of a cement factory, the interaction between the cement and water produces a tough, very sticky layer. Around highways, the wear of car tires produces a slick, tar-like carbon deposit on the insulator’s surface.

Moisture, fog, and dew wet the pollution layer, dissolve the salt, and produce a conducting layer, which in turn reduces the flashover voltage. The pollution can reduce the flashover voltage of a standard insulator string by about 20–25%.

Near the ocean, wind drives salt water onto insulator surfaces, forming a conducting salt-water layer which reduces the flashover voltage. The sun dries the pollution during the day and forms a white salt layer. This layer is washed off even by light rain and produces a wide fluctuation in pollution levels.

The Equivalent Salt Deposit Density (ESDD) describes the level of contamination in an area. Equivalent Salt Deposit Density is measured by periodically washing down the pollution from selected insulators using distilled water.

The resistivity of the water is measured and the amount of salt that produces the same resistivity is calculated. The obtained mg value of salt is divided by the surface area of the insulator. This number is the ESDD. The pollution severity of a site is described by the average ESDD value, which is determined by several measurements.

VOLTAGE CONTROLS THROUGH CAPACITORS AND VOLTAGE REGULATORS BASICS AND TUTORIALS

Good quality electric service requires that the voltage at the consumers’ premises be kept within an acceptable voltage range for satisfactory operation of consumer equipment. At the 120-volt level, this is 110–126 volts at the utilization point.

It is customary for utilities to hold voltage at the customer meter location between 114 and 126 volts, which allows for a 4-volt drop to the utilization point in the residence. The location of the voltage extremes are usually at the first and last customer locations on the primary feeder.

During peak load conditions the first customer usually receives the highest voltage and the last customer the lowest. The variations from light to heavy load at these locations will establish the voltage range for the circuit.

As a first step in the control of voltage on such a circuit, most utilities will regulate the primary voltage at the substation. This takes care of variations in the voltage supplied to the substation and the variation on the feeder up to the first customers. The equipment usually used for regulation is tap changers on the substation transformers or separate feeder voltage regulators.

For most urban feeders, no other regulating equipment is needed, although shunt capacitor banks are often installed to supply part of the kilovar portion of the load. On larger or longer feeders, both voltage regulators and shunt-capacitor banks may be needed out on the feeders to provide supplementary voltage control and reactive supply.

In general, the control of voltage is more economical if both voltage regulators and shunt capacitors are used and if distribution voltage control is coordinated with voltage control of the transmission system and of generation.

Capacitors
Capacitors are applied as an economic tool to reduce system losses by supplying kilovars locally. Shunt capacitor banks including fixed and switched banks are used on primary feeders to reduce voltage drop, reduce power loss, and improve power factor.

The closer to the load they can be installed, the greater the economic benefit. Capacitors are not only an economic tool for the distribution system, but they can eliminate the need for adding reactive sources in the bulk power system. Kilovars supplied directly to load areas reduce the current in all portions of the system.

This releases transmission capacity and reduces system losses. At light load, the capacitors installed for full load operation may cause too high a voltage on the distribution system. Therefore, many capacitors will have to be switched off during these periods. Various means are used to perform the switching.

Voltage Regulators
Voltage regulators usually are an autotransformer with automatic tap-changing under load. Automatic measuring and tap-changing equipment holds the output voltage within a predetermined bandwidth.

By using the smallest practical bandwidth, more voltage drop can be allowed along the feeder, still keeping the consumer voltage within acceptable limits. The means for achieving this are an integral part of the regulator controls called the line drop compensator.

DISTRIBUTION CAPACITY OF POWER SYSTEM BASICS AND TUTORIALS

The capacity of the distribution system is determined in most cases by the thermal ratings of the equipment. In more rural areas with low load density it may be determined by voltage limits.

The distribution substation capacity depends on the size of transformers and the provision of an additional spare transformer. If a substation has two transformers, all load must be supplied by the remaining one if one fails.

In this case, the substation capacity will depend on the capability of the remaining transformer to carry the load for the time required to replace the failed transformer, with the capacity being lower if the replacement time is longer.

For substations with a single transformer, load is limited to what can be transferred to other substations at remote feeder tie points.

The allowable primary feeder loading can be limited by the size of conductors used and the characteristics of the load supplied. If the load varies, higher maximum loads can be carried by the feeder than steady loads, since the rating of the feeder depends on the heating effect of the current over time.

Feeder loading may also be limited by the voltage drop that occurs at the end of longer feeders.

The distribution transformer capacity is determined by the size of the transformer and the characteristics of the load. In some cases, the distribution transformers are single phase. When a three phase supply is needed, three single phase transformers can be used, each connected to a different phase of the three-phase primary supply.

Alternatively, a three-phase transformer may be used in which the three phases are in a single tank. The capacity of the secondaries is determined by the size of wire used, their length, and the characteristics of the load they supply.

PRIMARY DISTRIBUTION FEEDER TYPES BASICS AND TUTORIALS

Primary voltage in the “13 kV class” is predominating among United States utilities. The 4-kV class primary systems are older and are gradually being replaced. In some cases 34 kV is used in new, high-density-load areas.

The three-phase, four-wire primary system is the most widely used. Under balanced operating conditions, the voltages of each phase are equal in magnitude and 120° out of phase with each of the other two phases.

The fourth wire in these Y-connected systems is used as a neutral for the primaries, or as a common neutral when both primaries and secondaries are present. The common neutral is also grounded at frequent intervals along the primary feeder, at distribution transformers, and at customers’ service entrances.

Rural and suburban areas are usually served by overhead primary lines, with distribution transformers, fuses, switches, and other equipment mounted on poles. Urban areas with high-density loads are served by underground cable systems, with distribution transformers and switchgear installed in underground vaults or in ground-level cabinets.

There is also an increasing trend toward underground single-phase primaries serving residential areas. Underground cable systems are highly reliable and unaffected by weather, but can have longer repair times. The costs of underground distribution are significantly higher than overhead. Primary distribution includes three basic types: (1) radial, (2) loop, (3) and primary network systems.

Radial Systems
The radial system is a widely used, economical system often found in low-load density areas. To reduce the duration of interruptions, overhead feeders can be protected by automatic reclosing devices located at the substation or at various locations on the feeder.

These devices reenergize the feeder if the fault is temporary. To further reduce the duration and extent of customer interruptions, sectionalizing fuses are installed on branches of radial feeders allowing unaffected portions of a feeder to remain in service.

Loop Systems
The loop system is used where a higher level of service reliability is desired. Two feeders form a closed loop, open at one point, so that load can be transferred from one feeder to another in the event of an outage of one circuit by closing the open point and opening at another location.

One or more additional feeders along separate routes may be provided for critical loads, such as hospitals that cannot tolerate long interruptions. Switching from the normal feeder to an alternate feeder can be done manually or automatically with circuit breakers and electrical interlocks to prevent the connection of a good feeder to a faulted feeder.

Primary Network Systems
The primary network system consists of a grid of interconnected primary feeders supplied from a number of substations. It provides higher service reliability and quality than a radial or loop system. Only a few primary networks are in operation today. They are typically found in downtown areas of large cities with high load densities.

UNACCOUNTED ENERGY AND LOSSES ON DELIVERY SYSTEM BASICS AND TUTORIALS

All the energy that leaves the generating stations is not reflected in the bills sent to customers. The difference is attributable to two issues. The first is called unaccounted-for energy. This energy is not metered by the local utility and is usually due to theft of service.

In some underdeveloped countries this category can be as much as 50% of the energy generated. The second is the losses in the system directly related to the electric characteristics of the delivery system. They are an important consideration when selecting new electric power policies, when locating new generating plants, when deciding what generator to run to supply the next increment of load, when deciding on the voltage level and conductor sizes for new transmission and when deciding on the amount of voltage support to provide.

Losses occur in both lines and transformers. Line losses are directly related to the square of the value of the current (I2R).The greater the amount of electricity the delivery system carries, and the greater the distance the greater the amount of energy lost as heat.

Transformer losses are of two types: no-load loss and load loss. No-load losses are related to hysteresis and eddy-current loss in the transformer core and are independent of the current. Transformer load loss is related to I2R.

The no-load losses vary as the third to fifth power of the voltage and increase significantly when voltages are outside of design range.

Transformer manufacturers consider the amount of losses as one element of the requirements when designing a transformer. Typically, the cost of anticipated losses is a tradeoff with the capital cost to purchase the transformer.

Losses can be reduced by increasing the size, and hence the cost, of a transformer. Rustebakke2 reports that the total losses at rated transformer output amount to approximately 0.3–0.6% of the rated kiloVolt-Amperes of the unit.

On most power systems load losses are 60% to 70% of total losses with transformer no load losses being from 30%–40%. In recent years, as the wholesale electric power market has been deregulated; new dispatch procedures and the increased flow of electricity on the bulk transmission system over longer distances without a commensurate increase in transmission capacity has caused an increase in transmission losses.

LOAD DIVERSITY EFFECTS AND COINCIDENCE IN POWER SYSTEM DISTRIBUTION TUTORIALS

There are two types of load diversity—that of different peak loads between customer classes, and that of different peak loads at different hours of the day and days of the year.

From continuously recorded demand data, a number of different demand measures may be derived.The most commonly metered measure of customer demand is individual customer maximum demand.This measure indicates the highest demand level incurred by the customer during any metering interval in a billing period. Due to varying types and uses of electrical equipment across customers, there are broad differences in the times that customers achieve their individual maximum demands.

For example, one customer whose major use of electricity is outdoor light may regularly experience maximum demand in the late evening hours of the day; while a second customer, whose major requirement for electricity is for air conditioning, is more likely to experience a maximum demand during afternoon hours in the summer months.

Furthermore, the electrical load requirements of an industrial process may be closely tied to work shift hours, or may be nearly flat throughout the 24-hour day if the process operates on a continuous basis. These differences in the timing of individual maximum demands are referred to as diversity.

Diversity in load requirements not only exists among individual customers, but also can be observed among rate classes, customer classes, jurisdictional divisions, utility systems, and power pools.

The inverse of diversity is coincidence. Coincident demand measures the maximum amount of load which occurs within a given measurement interval. If a customer has two or more electricity consuming devices at their facility, or residence, the customer’s individual maximum demand will occur at the time at which the requirements of the individual devices are most highly coincident (i.e., demonstrate the least diversity).

The sum of the maximum requirements of the individual devices will always be greater than, or equal to, the customer’s individual maximum demand. Other measures of individual customer demands tend to relate the individual customer’s requirements to rate class, customer class, jurisdictional, or system requirements.

Owing to diversity among customers, each individual customer’s contribution to class, jurisdictional, or system maximum requirements, cannot be greater than, and tends to be less than; the customer’s individual maximum demand.

System, jurisdictional, class, or customer demand are typically measured on an annual, monthly, or daily basis. However, billing data (both demand and energy measures) typically do not correspond directly to calendar month or calendar year measures.

Usage reported on a bill in January, for example, may include substantial amounts of consumption which occurred in December of the previous year. This occurs because cost-effective meter reading and bill processing schedules generally require that not all meters be read on the same day but rather some are read on each working day of each month.

Each customer is billed based on his metered consumption in the prior billing cycle. Measures of actual requirements on a calendar month basis are not available for individual customers, except where expensive continuously recording demand meters are installed.

At the system level, monthly aggregate requirements are usually determined by adding net electricity interchange into and out of an area to the net generation within the area from continuously recorded data typically maintained by utilities at the generation and transmission levels.

TYPES OF ELECTRICAL MACHINE WINDING BASICS AND TUTORIALS

(a) Coil winding
The winding consists of coils wound on all the poles of the machine and connected together to form a suitable series or parallel circuit. The direction of the current in the alternate pole will be opposite so that when one pole is the North Pole, the other adjacent pole will be a South Pole.

This produces the flux in the proper direction, completing the magnetic circuit from the North Pole to the South Pole through the iron cores of both the stator and the rotor.

The coil may be wound on the stator or on the rotor, forming the salient or non-salient poles of the machine. The DC supply is given to these windings and they produce a field proportional to the magnitude of the current through the windings. If the poles are on the stator, a stationary field is produced in the air gap.

(b) Commutator winding
The commutator winding is on the rotor. The armature has open slots and the conductors are located in these slots and connected to the commutator segments in a continuous sequence.

(c) Polyphase winding
Polyphase winding is a distributed winding. Individual conductors are distributed in slots in a suitable way and connected into a number of separate circuits, one for each phase. The group of conductors forming the phase bands is distributed in a regular sequence over the successive pole pitches so that there is balanced winding that produces an equal voltage per phase.

This type of winding is mainly used for the stator. When supplied with three-phase currents it produces a rotating field in the air gap. This is of a constant magnitude but rotating at a constant synchronous speed.

TRANSMISSION LINE STRUCTURE TYPE SELECTION FACTORS TUTORIALS

There are usually many factors that impact on the selection of the structure type for use in an OHTL. Some of the more significant are briefly identified below.

Erection Technique: It is obvious that different structure types require different erection techniques. As an example, steel lattice towers consist of hundreds of individual members that must be bolted together, assembled, and erected onto the four previously installed foundations.

A tapered steel pole, on the other hand, is likely to be produced in a single piece and erected directly on its previously installed foundation in one hoist.

The lattice tower requires a large amount of labor to accomplish the considerable number of bolted joints, whereas the pole requires the installation of a few nuts applied to the foundation anchor bolts plus a few to install the crossarms.

The steel pole requires a large-capacity crane with a high reach which would probably not be needed for the tower.

Therefore, labor needs to be balanced against the need for large, special equipment and the site’s accessibility for such equipment.

Public Concerns: Probably the most difficult factors to deal with arise as a result of the concerns of the general public living, working, or coming in proximity to the line. It is common practice to hold public hearings as part of the approval process for a new line.

Such public hearings offer a platform for neighbors to express individual concerns that generally must be satisfactorily addressed before the required permit will be issued. A few comments demonstrate this problem.

The general public usually perceives transmission structures as “eyesores” and distractions in the local landscape. To combat this, an industry study was made in the late 1960s (Dreyfuss, 1968) sponsored by the Edison Electric Institute and accomplished by Henry Dreyfuss, the internationally recognized industrial designer.

While the guidelines did not overcome all the objections, they did provide a means of satisfying certain very highly controversial installations (Pohlman and Harris, 1971). Parents of small children and safety engineers often raise the issue of lattice masts, towers, and guys, constituting an “attractive challenge” to determined climbers, particularly youngsters.

Inspection, Assessment, and Maintenance: Depending on the owning utility, it is likely their in house practices will influence the selection of the structure type for use in a specific line location. Inspections and assessment are usually made by human inspectors who use diagnostic technologies to augment their personal senses of sight and touch.

The nature and location of the symptoms of critical interest are such that they can be most effectively examined from specific perspectives. Inspectors must work from the most advantageous location when making inspections.

Methods can include observations from ground or fly-by patrol, climbing, bucket trucks, or helicopters. Likewise, there are certain maintenance activities that are known or believed to be required for particular structure types.

The equipment necessary to maintain the structure should be taken into consideration during the structure type selection process to assure there will be no unexpected conflict between maintenance needs and r-o-w restrictions.

Future Upgrading or Uprating: Because of the difficulty of procuring r-o-w’s and obtaining the necessary permits to build new lines, many utilities improve their future options by selecting structure types for current line projects that will permit future upgrading and/or uprating initiatives.

METHODS FOR IMPROVING TRANSMISSION LINE INSULATORS PERFORMANCE

Contamination caused flashovers produce frequent outages in severely contaminated areas. Lines closer to the ocean are in more danger of becoming contaminated. Several countermeasures have been proposed to improve insulator performance.

The most frequently used methods are:

1. Increasing leakage distance by increasing the number of units or by using fog-type insulators. The disadvantages of the larger number of insulators are that both the polluted and the impulse flashover voltages increase. The latter jeopardizes the effectiveness of insulation coordination because of the increased strike distance, which increases the overvoltages at substations.

2. Application insulators are covered with a semiconducting glaze. A constant leakage current flows through the semiconducting glaze. This current heats the insulator’s surface and reduces the moisture of the pollution. In addition, the resistive glaze provides an alternative path when dry bands are formed.

The glaze shunts the dry bands and reduces or eliminates surface arcing. The resistive glaze is exceptionally effective near the ocean.

3. Periodic washing of the insulators with high-pressure water. The transmission lines are washed by a large truck carrying water and pumping equipment. Trained personnel wash the insulators by aiming the water spray toward the strings.

Substations are equipped with permanent washing systems. High-pressure nozzles are attached to the towers and water is supplied from a central pumping station. Safe washing requires spraying large amounts of water at the insulators in a short period of time.

Fast washing prevents the formation of dry bands and pollution-caused flashover. However, major drawbacks of this method include high installation and operational costs.

4. Periodic cleaning of the insulators by high pressure driven abrasive material, such as ground corn cobs or walnut shells. This method provides effective cleaning, but cleaning of the residual from the ground is expensive and environmentally undesirable.

5. Replacement of porcelain insulators with nonceramic insulators. Nonceramic insulators have better pollution performance, which eliminates short-term pollution problems at most sites. However, insulator aging may affect the long-term performance.

6. Covering the insulators with a thin layer of room-temperature vulcanized (RTV) silicon rubber coating. This coating has a hydrophobic and dirt-repellent surface, with pollution performance similar to nonceramic insulators.

Aging causes erosion damage to the thin layer after 5–10 years of operation. When damage occurs, it requires surface cleaning and a reapplication of the coating.

Cleaning by hand is very labor intensive. The most advanced method is cleaning with high pressure driven abrasive materials like ground corn cobs or walnut shells. The coating is sprayed on the surface using standard painting techniques.

7. Covering the insulators with a thin layer of petroleum or silicon grease. Grease provides a hydrophobic surface and absorbs the pollution particles.

After one or two years of operation, the grease saturates the particles and it must be replaced. This requires cleaning of the insulator and application of the grease, both by hand. Because of the high cost and short life span of the grease, it is not used anymore.

THINGS TO LOOK FOR IN AN ELECTRICAL DRAWING DURING TROUBLE SHOOTING

Things to look for in an electrical drawing

1. The symbols shown for a device in a circuit represent its de-energized state when no power is applied. It is either a timer NO/NC contact or a relay NO/NC contact in a circuit. In addition, power devices such as circuit breakers and contactors are provided with NO and NC auxiliary contacts which are used for indicating the status of the device in signaling and interlocking circuits.

2. An electrical drawing has a sheet number and each sheet is divided into columns listed vertically as A, B, C, D and horizontally as 1, 2, 3, 4. This kind of matrix arrangement helps in quickly locating a particular device or contact in a sheet. Similarly, it is used to cross-reference a contact.

3. In order to identify different coils and their contacts a letter such as K1, K2 or C1, C2 is placed next to the circle of the coil. Contacts of the same contactor coil are shown with the same letter in the drawing.

4. Particular relay contacts may be used in different circuits at different locations. To give the reader an exact idea of where it is used, a drawing mentions a cross-reference number for each contact showing the sheet number and its matrix number.

5. In general, a heavy line is used to show high current-carrying conductors (mains supply lines, motor connection leads). In contrast, light-looking lines are used to represent low current-carrying conductors (control circuit lines).

6. Control circuit power lines are shown as L1 and L2; load (coils of relay) is connected between these two lines in series with switches, fuses, etc.

7. Conductors intersecting each other with no electrical junction in between are represented with an intersection without any dot. Conversely, conductors having an electrical junction are represented with a dot at the intersection.

8. A broken line in an electrical circuit represents mechanical action. Generally, it is associated with a push button or switch closing or opening a contact. Sometimes these lines can also indicate in combination with suitable additional symbols, a mechanical interlocking between two or more devices such as contactors or circuit breakers.

9. Dotted lines are used to differentiate an enclosure from field devices.

10. A wiring diagram of electric equipment represents the physical location of the various devices and their interconnections.

11. In an electrical drawing, conductors are marked with cross lines and dimensions of conductors are given alongside. This is used to represent the conductor size of a particular section in a drawing.

WHY IS POWER TRANSMITTED AT HIGHER VOLTAGE?

When a particular amount of power has to be transmitted over a certain distance the following aspects need to be considered to decide the best voltage.

A lower voltage the need higher size conductors to withstand the high current is involved. There is a physical limitation to the size of conductor. Also, the percentage voltage drop may become excessive.

A higher voltage will make the conductor size manageable and reduce the voltage drop (% value) but the cost of the line becomes high due to larger clearances needed.

The best voltage will be one in which the total operational cost which the sum of the annualized capital cost (of the line) and the running cost due to power loss in the line is the lowest.

In practice, it is found that transmitting bulk power over long distances is economical if done in the HV range. The actual voltage will vary based on the distanceand quantum of power. Distribution circuits where typically the amount of power and distance involved are both lower, the best voltage is in the MV range (11, 22 or 33 kV).

For the same reason, low voltage circuits are found only in local sub-distribution circuits.

WHY IS TRANSFORMER RATING DEFINED IN KVA?

A transformer, unlike a motor, has no mechanical output (expressed in kW). The current flowing through it can vary in power factor, from zero PF lead (pure capacitive load) to zero PF lag (pure inductive load) and is decided by the load connected to the secondary.

The conductor of the winding is rated for a particular current beyond which it will exceed the temperature for which its insulation is rated irrespective of the load power factor. Similarly, the voltage that can be applied to a transformer primary winding has a limit.

Exceeding this rated value will cause magnetic saturation of the core leading to distorted output with higher iron losses.

It is therefore usual to express the rating of the transformer as a product of the rated voltage and the rated current (VA or kVA). This however does not mean that you can apply a lower voltage and pass a higher current through the transformer.

The VA value is bounded individually by the rated voltage and rated current.

ELECTRIC FIELD AND MAGNETIC FIELD DIFFERENCES AND BASICS TUTORIALS

When something occurs at one point in space because something else happened at another point, with no visible means by which the "cause" can be related to the "effect," we say the two events are connected by a field. In radio work, the fields with which we are concerned are the electric and magnetic, and the combination of the two called the electromagnetic field.

A field has two important properties, intensity (magnitude) and direction. The field exerts a force on an object immersed in i t ; this force represents potential (ready-to-be-used) energy, so the potential of the field is a measure of the field intensity.

The direction of the field is the direction in which the object on which the force is exerted will tend to move. An electrically charged object in an electric field will be acted on by a force that will tend to move it in a direction determined by the direction of the field.

Similarly, a magnet in a magnetic field will be subject to a force. Everyone has seen demonstrations of magnetic fields with pocket magnets, so intensity and direction are not hard to grasp.

A "static" field is one that neither moves nor changes in intensity. Such a field can be set up by a stationary electric charge (electrostatic field) or by a stationary magnet (magnetostatic field). Rut if either an electric or magnetic field is moving in space or changing in intensity, the motion or change sets up the other kind of field.

That is, a changing electric field sets up a magnetic field, and a changing magnetic field generates an electric field. This interrelationship between magnetic and electric fields makes possible such things as the electromagnet and the electric motor.

It also makes possible the electro-magnetic waves by which radio communication is carried on, for such waves are simply traveling fields in which the energy is alternately handed back and forth between the electric and rnagnetic fields.

Lines of Force
Although no one knows what it is that composes the field itself, it is useful to invent a picture of it that will help in visualizing the forces and the way in which they act. A field can be pictured as being made up of lines of force, or flux lines.

These are purely imaginary threads that show, by the direction in which they lie, the direction the object on which the force is exerted will move. The number of lines per unit of area (square inch or square centimeter) is called the flux density.

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AUDIO TONE RELAYING TUTORIALS AND BASICS

Application of audio-tone systems for protective relaying can be divided into two categories:

Transformer and Circuit Breaker Failure Protection or Other Direct Trip Applications
These applications are termed “direct transfer tripping.” The audio-tone system functions as the communication link to extend relay tripping circuits to remote circuit breaker locations.

These type of direct transfer tripping applications have the greatest difficulty in meeting the relay demands. These systems, with few exceptions, cannot have fault detector supervision of the receivers and the security against undesired tripping rests solely with the audiotone equipment.

Transmission Line Protection
Audio-tone systems function as the communication link for pilot relaying schemes employed for transmission line protection. Transfer trip schemes, including direct underreaching, permissive underreaching, and permissive overreaching protection are used extensively with telephone channels.

Directional comparison blocking and phase comparison schemes are used primarily with power line carrier but they are also employed with audio-tone systems over telephone channels and microwave channels. Tripping with line protective schemes can be made dependent on line relay and fault detector relay operation.

Transformer and Circuit Breaker Failure Protection
Transfer tripping schemes using audio-tone systems over telephone channels have been used extensively for transformer protection where high voltage breakers have been omitted or for breaker backup protection where system arrangement places a backup breaker(s) at a remote location. The operation of a frequency shift audio-tone system for remote clearing is described in the following paragraph.

During normal conditions, a guard signal(s) is transmitted continuously. Receipt of the guard signal by the tone receiver produces blocking of the breaker trip circuit. At the same time, the guard signal provides continuous monitoring of the tone system.

When the protective relays detect abnormal operation, they initiate removal of the guard signal(s) and transmission of the trip signal(s). The absence of guard and the reception of the trip constitutes a valid trip condition to effect remote clearing.

Transmission Line Protection
Pilot relaying systems applicable for the protection of power-transmission lines and for which audio tone channels may be used are briefly described below. The transmission lines may have two or more terminals each with circuit breakers for disconnecting the line from the rest of the power system.

All of the relaying systems described can be used on two-terminal or multiterminal lines. These relaying systems program the automatic operation of the circuit breakers during power system faults.

Where possible, fault detector relays should supervise the receiver relay trip circuits to improve security.

However, their use should not be a substitute for an audio-tone system of highest reliability, since the greatest noise levels are likely to occur at the very instant when the fault detectors have operated, that is during a power system fault.

POWER TRANSFORMER AFTER FAULT REENERGIZING PRACTICE TUTORIALS

There is no universal practice with respect to reenergizing a transformer that has been disconnected from the system by relay action that may have been caused by a transformer fault. Since no one would intentionally energize an internally faulted transformer, the differences in practice seem to be based on the lack of knowledge of where the fault was or whether there was a fault.

Consider a transformer differential arrangement that includes external leads. A fault within the differential zone may not be an internal fault. If the transformer has a pressure relay, this may give indication of an internal fault. If not, one has to rely on the presence or lack of evidence indicating an external fault. In the absence of definite information that a fault was external, most operating companies will not reenergize the power transformer without a complete check.

Now consider a form of transformer protection that includes just the transformer. This may be a differential relay (operating from transformer bushing CTs) or a pressure relay. The one reason to reenergize a transformer so protected is the lack of confidence in the relays. While a few may reenergize a transformer so protected, it may be argued that such a practice does not appear to be warranted with modern relays.

The use and location of the transformer will affect the decision whether or not to reenergize. One is less likely to reenergize a generator step-up transformer or a large system tie transformer than a small substation transformer. The presence of a spare transformer would lessen the necessity to reenergize right away. A history of failures of a certain type transformer may affect the decision by operating companies to reenergize that type of transformer.

If a user’s practice is not to reenergize after a protective relay has disconnected the transformer from the system, a real and continuing problem is how to proceed after such a relay operation; that is, if no fault is evident on visual inspection, what should be done to determine whether or not an actual fault exists?

Several tests are available to check a transformer prior to reenergizing. Turns ratio tests, resistance tests, and low-voltage impulse tests are available, but gas analysis is now the most used test. Gas analysis has become increasingly popular and found to be quite reliable when properly performed. See IEEE Committee Report [B51] and Pugh and Wagner [B76].

Normally, power transformers are not reenergized by automatic reclosing schemes except where the transformer may be connected to a line or bus that may be reenergized after a relay trip by the line or bus-protective relays. The transformer protective relays usually operate a lockout relay that trips the local interrupting devices (power circuit breaker, circuit switcher, or disconnect switch) and prevents the devices from closing.

Where a local interrupting device is not present, transfer trip may be used to operate a remote interrupting device. The transfer trip may also be used to lock out the remote interrupting device, thus preventing reenergizing the transformer.

If an automatic grounding switch is used on the high side of a transformer and high-speed reclosing is used on the line, the transformer will probably be reenergized before a high-side motor-operated disconnect switch (MODS) can open.  However, if delayed reclosing is used on the line, the MODS will have time to open and the transformer will not be reenergized.

Usually, high-speed reclosing would not be used on lines with automatic grounding switches. If a transformer tapped on a line is fused on the high side, there is no way to prevent its reenergizing if the line relays detect the fault and trip, unless all three fuses blow.

Philosophies have changed somewhat in recent years, in that operating companies seem to have an increasing reluctance to reenergize transformers after a protective relay operation where the transformer might be subjected to a second fault. This reluctance is partly because of recent transformer failure rates and partly because of increased cost and time to repair internal failures. 

Also, operating companies are gaining more confidence in protective relays, particularly pressure relays.

TRANSFORMER FAILURE TYPES TUTORIALS AND BASICS

The electrical windings and the magnetic core in a transformer are subject to a number of different forces during operation, for example

a)Expansion and contraction due to thermal cycling
b)Vibration
c)Local heating due to magnetic flux
d)Impact forces due to through fault current
e)Excessive heating due to overloading condition on inadequate cooling

These forces can cause deterioration and failure of the winding electrical insulation. Table 1 summarizes failure statistics for a broad range of transformer failure causes reported by a group of U.S. utilities over a period of years.

The detection systems that monitor other transformer parameters can be used to indicate an incipient electrical fault. Prompt response to these indicators may help avoid a serious fault. For example

a) Temperature monitors for winding or oil temperature are typically used to initiate an alarm requiring investigation by maintenance staff.

b) Gas detection relays can detect the evolution of gases within the transformer oil. Analysis of the gas composition indicates the mechanism that caused the formation of the gas; e.g., acetylene can be caused by electrical arcing, other gases are caused by corona and thermal degradation of the cellulose insulation.

The gas detection relays may be used to trip or alarm depending on utility practice. Generally, gas analysis is performed on samples of the oil, which are collected periodically. Alternatively, a continuous gas analyzer is available to allow on-line detection of insulation system degradation.

c) Sudden-pressure relays respond to the pressure waves in the transformer oil caused by the gas evolution associated with arcing.

d) Oil level detectors sense the oil level in the tank and are used to alarm for minor reductions in oil level and trip for severe reductions.

POWER TRANSFORMER GAS ANALYSIS TUTORIALS AND BASIC

Electrical faults in oil-filled transformers usually generate gases, some of which are combustible. Many transformer faults in their early stages are incipient and deterioration is gradual, but sufficient quantities of combustible gases are usually formed to permit detection and allow corrective measures to forestall a serious outage.

Depending on the transformer oil preservation system, the gas may either be dissolved in the oil or enter the gas space above the oil. In certain types of transf

These relays are usually set to alarm for the presence of gas. It is common practice to draw off samples of oil or gas for periodic analysis of combustible gas content. If there is a gas space in the oil preservation system, it is possible to directly draw off a sample of the gas and perform an on-the-spot analysis with a portable gas analyzer.

If there is no gas space in the transformer, it is necessary to analyze an oil sample for dissolved gas content by gas chromatography (see Bean and Cole [B69]).

The presence of key gases is an indicator of the location of the source of the gas

a) Hydrogen is generated by corona or partial discharges. The presence of other key gases can indicate the source of the discharge.

b) Ethylene (C2H4) is the key gas associated with the thermal degradation of oil. Trace generation of associated gases (ethane and methane) may start at 150 °C. Significant generation of ethylene begins around 300 °C.

c) Carbon monoxide and carbon dioxide are generated when cellulose insulation is overheated.

d) Acetylene (C2H2) is produced in significant quantities by arcing in the oil. To interpret the results of the analysis, the relative ratios of key gases are used.

There has been substantial work to define the best methods for interpreting the results and guidelines have been published in IEEE Std C57.104-1991 [B74] and IEC 60599: 1978 [B8].

Gas analysis on transformers should be made periodically by manual or automatic methods. The interval between tests may be varied according to size, importance, loading, and exposure to faults.

This test should also be made after protective relay or relief diaphragm operation and before reenergizing, if practical. It should be made on new transformers after installation and original loading.

DIFFERENCES BETWEEN STRANDED AND SOLID CONDUCTORS BASICS AND TUTORIALS

Because of the helical path of the strand layers there is more length of metal in a given length of stranded conductor than in a solid round conductor of the same AWG size, hence both the weight and dc resistance per unit length are increased. The amount of increase for all-aluminum conductors may be computed according to a method described in ASTM B 23 1, may be used.

The tensile load on a conductor is not always equally divided among the strands. This effect can reduce the total load at which the first strand breaks as compared with that of a solid conductor of equal cross section. However, this effect is more than offset by the fact that the unit tensile strength of commercially cold-drawn wire generally increases as its diameter is reduced, as is evident by the comparison for H19 stranded conductor.

According to ASTM Standards, aluminum conductors that are concentric-lay stranded of 1350 or 6201 alloys in the various tempers have their rated tensile strength (or minimum rated strength) taken as the following percentages of the sum of the minimum average tensile strengths of the component wires, multiplied by rating factors, as below:

7 wires per conductor One layer 96%
19 wires per conductor Two layers 93 %
37 wires per conductor Three layers 91 %
61 wires per conductor Four layers 90%
91 wires per conductor Five layers 89 %

Similarly, the rated strength of ACSR is obtained by applying rating factors of 96, 93, 91, and 90 percent, respectively, to the strengths of the aluminum wires of conductors having one, two, three, or four layers of aluminum wires, and adding 96 percent of the minimum stress in the steel wires at 1 .O percent elongation for cables having one central wire or a single layer of steel wires, and adding 93 percent of the minimum stress at 1 .O percent elongation if there are two layers of steel wires. All strengths are listed in pounds to three significant figures, and these strengths also apply to compact round conductors.

Special Conductor Constructions
Large conductors requiring exceptional flexibility may be of rope-lay construction. Rope-lay stranded cables are concentric-lay stranded, utilizing component members which are themselves either concentric stranded or bunched.

Bunched members are cabled with the individual components bearing no fixed geometric relationship between strands. Rope-lay stranded conductors may be stranded with subsequent layers reversing in direction, or may be unidirectional with all layers stranded in the same direction but with different lay lengths.

Some cables are designed to produce a smooth outer surface and reduced overall diameter for reducing ice loads, and under some conditions wind loading. The stranded cables are smoothed in a compacting operation so that the outer strands loose their circularity; each strand keys against its neighbor and many interstrand voids disappear.

A similar result is commonly obtained by use of trapezoidal strands that intertie with adjacent strands to create a smooth, interlocking surface.

Another cable design, expanded core concentric-lay conductor, uses fibrous or other material to increase the diameter and increase the ratio of surface area to metal cross-section or weight. Designed to minimize corona at voltages above 300 kV, they provide a more economical balance between cable diameter and current carrying capacity.

A “bundled” conductor arrangement with two or more conductors in parallel, spaced a short distance apart, is also frequently used for HV or EHV lines. Although the ratio of radiating area to volume increases as the individual conductor size decreases, the design advantages of bundling are not wholly dependent upon ampacity.

Normal radio interference, etc., and the usual controlling design characteristics are discussed elsewhere, but the current carrying capacity relationship is similar.

Thus, two 795 kcmil ACSR Drake under typical conditions of spacing and temperature provide 24 percent more ampacity per kcmil than a single i780 kcmil ACSR Chukar.

SAFETY AUDIT CHECKLIST SAMPLE TUTORIALS

This checklist provides an assessment of the minimum requirements needed to safely operate and maintain electric power systems. Below is a sample provided in IIEE STD 902-1998. You may modify it to suit your needs.

One-line diagram exists. Yes _____ No _____

One-line diagram is legible. Yes _____ No _____

One-line diagram is correct. Yes _____ No _____

All persons who operate the power system have easy access to the current one-line diagram.
Yes _____ No _____

Equipment is labeled correctly, legibly, and in accordance with the one-line diagram.
Yes _____ No _____

Persons who operate/maintain electrical equipment are trained for the voltage-class equipment they operate/maintain. Yes _____ No _____

De-energized procedures and equipment exist and are used. Yes _____ No _____

Energized work procedures exist and are followed. Yes _____ No _____

Equipment is grounded. Yes _____ No _____

Ground system is tested periodically. Yes _____ No _____

Electrical equipment is free from corrosion. Yes _____ No _____

Proper maintenance practices are followed, especially for fault protection equipment.
Yes _____ No _____

Recent (less than five years old) relay/fuse coordination study exists, and relays are calibrated to the setting recommended. Yes _____ No _____

Power system is resistance grounded. Yes _____ No _____

Written switching orders are used. Yes _____ No _____

ELECTRICAL EQUIPMENT TESTING AND MAINTENANCE INFORMATION SOURCES TUTORIALS

The following is an alphabetical listing of the groups that provide procedures and specifications for electrical testing and maintenance:

a) American National Standards Institute (ANSI);

b) American Society for Testing and Materials (ASTM);

c) Association of Edison Illuminating Companies (AEIC);

d) Institute of Electrical and Electronics Engineers (IEEE);

e) Insulated Cable Engineers Association (ICEA);

f) InterNational Electrical Testing Association (NETA);

g) National Electrical Manufacturers Association (NEMA);

h) National Fire Protection Association (NFPA);

i) Occupational Safety and Health Administration (OSHA).

ELECTRICAL EQUIPMENT MAINTENANCE FUNDAMENTALS TUTORIALS (IIEE STD 902-1998)

Inspection and testing
The condition of electrical equipment is generally affected by the atmosphere and conditions under which the equipment is operated and maintained. Water, dust, temperature, humidity, corrosive fumes, vibration, and other environmental factors can adversely affect electrical equipment.

Electrical equipment life can be extended dramatically by simple precautions that promote cleanliness, dryness, tightness, and the prevention of friction. The thoroughness of maintenance procedures can be categorized into three different levels:

Level 1-General inspection and routine maintenance;
Level 2-Inspection, general tests, and preventive maintenance;
Level 3-Inspection, speciÞc tests, and predictive maintenance.

Testing would include
a) Insulation tests;
b) Protective device tests;
c) Analytical tests (e.g., time travel analysis, dissolved gas analysis, infrared, and contact resistance);
d) Grounding tests;
e) Functional tests.

The following equipment should be in the maintenance program:
-Switchboards and switchgear assemblies
-Disconnecting switches
-Circuit breakers
-Capacitors
-Surge arresters
-Current transformers
-Voltage transformers
-Protective relays
-Network protectors
-Fuses
-Batteries and battery chargers
-Meters and other instruments
-Alarms and alarm systems
-Grounding
-Ground detection schemes
-Transformers
-Insulating liquids
-Cables
-Busways
-Busducts
-Motor control center and motor starters
-Motor protective devices
-Motor drives
-Transformer auxiliary systems
-Rotating equipment
-Lighting
-Wiring devices
-Uninterruptible power supplies
-Transfer switches
-Test and safety equipment

Repairs
Repairs can be categorized by their sense of urgency. Some repairs must be accomplished before the equipment can be returned to service. Other repairs may require material items that are not stocked, and cannot be accomplished until those items have been received and properly installed.

Some repairs can be postponed, thus allowing the electrical system to go back into service without undue risk. In this method, the repair could be scheduled for a future date when it is more convenient to the plant.

A part of EPM is determining which spare equipment or parts should be kept in stock, such as fuses, circuit breakers, and other components, in order to be able to repair critical items and return a shut-down facility to operation. This, like the maintenance procedure itself, is an economic
benefit vs. cost of inventory balancing act.

Failure analysis
When equipment fails, it is important to understand the reason why. Failure analysis, when done properly, locates the root cause of the failure. This is important in order to take the necessary steps to prevent similar failures in the future.

Failure analysis involves an effort to reconstruct, at least mentally, the conditions that existed prior to failure and the events that led to the nature of the failure. It is through this process that the root cause can be determined.

There are engineers that specialize in forensic and failure analysis. These people, through their experience, are generally able to recognize failure patterns and to draw accurate conclusions much more readily than the untrained person. This is a specialty that is generally contracted when firms do not have that capability in-house.

Inspection and test frequency
Equipment in a critical service would generally receive maintenance attention more frequently than other equipment. Manufacturer's service manuals should be consulted in determining an adequate frequency.

They generally give frequencies that are based upon a standard, or average, or upon operating conditions. This is a good basis from which to start in determining the frequency for a given facility. A good guide for both maintenance frequency and routine inspections and tests is found in NFPA 70B-1994 [B3].

Proper maintenance record keeping, together with periodic reviews, should reveal where adjustments to the frequency may be necessary, based on the actual effectiveness of the maintenance program.

USES AND APPLICATION OF SINGLE LINE DIAGRAM TUTORIALS AND BASICS

Uses of the single-line diagram
The single-line diagram may be used in a number of important ways in operating and maintaining an industrial or commercial power distribution system. Frequently, the single-line diagram, with all of the listed information, becomes too crowded for information to be used
effectively in some of the operating activities.

In those instances, it is wise to produce a set of single-line diagrams, with each different diagram in the set containing the pertinent information that is required for a particular activity or set of activities. Some of the needs for special single-line diagrams are

a)Switching functions.
When the primary use of the diagram is to provide information to system operators for switching in order to isolate portions for maintenance or for load control, then only the data required to make the decisions necessary for system switching are included on the diagram.

Sometimes, when the distribution system is complex, a separate version of the single-line diagram in block form is more usable than a complete single-line diagram. This may be identified as a “system operating diagram”.

b)Load flow control.
This diagram is used exclusively for load ßow control. It only includes the data that show system component capacities and other data that pertain to load flow.

c)Relaying and relay logic diagrams.
These single-line diagrams are used to describe the system protective relay systems. These diagrams are used particularly as logic and tripping diagrams that may contain a unique language used only to depict the sequence of relay or system protective component operation under various fault conditions.

d)Impedance diagram.
This is a single-line diagram that shows the system input impedance and the impedance of all system components in which the impedance of each circuit branch is maintained for system short-circuit analysis.

This diagram should include all reactance data on large rotating apparatus or the equivalent data for groups of machines.

CHARACTERISTICS OF AN ACCURATE SINGLE LINE DIAGRAM TUTORIALS

The following characteristics should help to ensure accuracy as well as ease of interpretation:

a)      Keep it simple. A fundamental single-line diagram should be made up of short, straight lines and components, similar to the manner in which a block diagram is drawn. It should be relatively easy to get the overall picture of the whole electrical system.

All, or as much as possible, of the system should be kept to one sheet. If the system is very large, and more than one sheet is necessary, then the break should be made at voltage levels or at distribution centers.

b)      Maintain relative geographic relations. In many cases, it is possible to superimpose a form of the one-line diagram onto the facility plot plan. This is very helpful toward a quick understanding of the location of the system's major components for operating purposes.

It may, however, be more difficult to comprehend the overall system operation from this drawing. Such a drawing could be used for relatively simple systems. For more complex systems, however, it should be used in addition to the fundamental single-line diagram.

c)      Maintain the approximate relative positions of components when producing the single-line diagram. The drawing should be as simple as possible and should be laid out in the same relationship as an operator would view the equipment. The diagram does not need to show geographical relationships at the expense of simplicity.

NOTE: A site plan with equipment locations may be required to accompany the single-line diagram.

d)     Avoid duplication. Each symbol, figure, and letter has a definite meaning. The reader should be able to interpret each without any confusion. In this regard, equipment names should be selected before publishing the document; then, these names should be used consistently.

e)      Show all known factors. All details shown on the diagram are important. Some of those important details are as follows:

            Manufacturers' type designations and ratings of apparatus;
            Ratios of current and potential transformers and taps to be used on multi-ratio transformers;
            Connections of power transformer windings;
            Circuit breaker ratings in volts, amperes, and short-circuit interrupting rating;
            Switch and fuse ratings in volts, amperes, and short-circuit interrupting rating;
            Function of relays. Device functions used should be from IEEE Std C37.2-1991;
            Ratings of motors, generators, and power transformers;
            Number, size, and type of conductors;
            Voltage, phases, frequency, and phase rotation of all incoming circuits.
The type of supply system (wye or delta, grounded or ungrounded) and the available short-circuit currents should be indicated.

f)       Future plans. When future plans are known, they should be shown on the diagram or explained by notes.

g)      Other considerations. Refer to IEEE Std 141-1993 for further discussion of single line diagrams.

TRANSMISSION LINES PERFORMANCE WITH VOLTAGE SENSITIVE LOADS - FREE PDF DOWNLOAD LINK

Abstract 
In this paper, transmission line performance with voltage sensitive loads is studied. Three types of load, namely constant power, constant current and constant impedance loads are considered, individually as well as in a mixed combination, and it is shown that the transmission line loss is highest with the constant power load and lowest with the constant impedance load. The line loss for mixed load is higher than that for constant power load when the constant power component is more pronounced in the mixed load.


Transmission lines constitute the arteries of an electric power system. The availability of a well-developed, high capacity system of transmission lines makes it technically and economically feasible to move large blocks of power over long distances.

Usually, transmission line performance is studied by considering constant power loads. The variation of power and reactive power taken by a load with various voltages is of importance when considering the manner in which such loads are represented in transmission line studies.

Most textbooks include transmission line
performance studies assuming constant power loads at the receiving end. The objective of the present paper is to incorporate the effects of the load characteristics into long-line theory to determine transmission line performance.

Although classical power flow load models which are functions of voltage have been used in production grade programs for load flow studies for years,  not much work has been done to study the performance of a single transmission line with voltage-sensitive loads.

Since a transmission line is an important component of the power system, the effects of voltage sensitive loads on its performance could form a part of the syllabus while presenting the transmission line theory in undergraduate classes. The work presented in this paper is based on the authors’ previous work on line losses and shunt compensation of EHV compensated transmission systems.

For constant power factor load, the active and reactive power demands, depending on the type of load, may remain constant with the voltage, change linearly with the voltage, or change as a function of the voltage squared. Constant impedance loads such as water heaters, electric ranges, series inductors and shunt capacitors are represented by RLC circuits and the active and reactive powers consumed  by such loads vary as the square of the voltage. The active power consumed by a lighting load containing incandescent lamps varies with voltage approximately as V.

The active power consumed by a lighting load consisting of fluorescent  lamps depends only slightly on voltage. Lighting load consumes no reactive  power. The active power consumed by a synchronous motor is approximately constant with change in voltage. For induction motors, the PV and QV characteristics are determined from the equivalent circuit, assuming shaft load to remain constant.

Read the rest of the document here...

PROGRAMMABLE LOGIC CONTROLLERS (PLC) BASICS TUTORIALS

The recommended controller for SCADA systems is the programmable logic controller (PLC).  PLCs are general-purpose microprocessor based controllers that provide logic, timing, counting, and analog control with network communications capability.

a. PLCs are recommended for the following reasons: 

(1)  They were developed for the factory floor and have demonstrated high reliability and tolerance for heat, vibration, and electromagnetic interference.

(2) Their widespread market penetration means that parts are readily available and programming and technical support services are available from a large number of control system integrators.

(3) They provide high speed processing, which is important in generator and switchgear control applications.

(4) They support hot standby and triple-redundant configurations for high reliability applications.

b. A PLC consists of the required quantities of the following types of modules or cards, mounted on a common physical support and electrical interconnection structure known as a rack. 

(1) Power supply: The power supply converts facility electrical distribution voltage, such as 120 VAC or 125 VDC to signal level voltage used by the processor and other modules.

(2) Processor: The processor module contains the microprocessor that performs control functions and computations, as well as the memory required to store the program.

(3) Input/Output (I/O): These modules provide the means of connecting the processor to the field devices.

(4) Communications: Communications modules are available for a wide range of industry-standard
communication network connections.  These allow digital data transfer between PLCs and to other systems within the facility.  Some PLCs have communications capability built-in to the processor, rather than using separate modules.

(5) Communication Media and Protocols:  The most common communication media used are copper-wire, coaxial, fiber-optics, and wireless.  The most common “open” communication protocols are  Ethernet, Ethernet/IP, and DeviceNet.  “Open” systems generally provide “plug and play” features in which the system software automatically recognizes and communicates to any compatible device that is connected to it.  Other widely accepted open protocols are Modbus, Profibus, and ControlNet.

(6) Redundancy: Many PLCs are capable of being configured for redundant operation in which one processor backs up another.  This arrangement often requires the addition of a redundancy module, which provides status confirmation and control assertion between the processors.  In addition, signal wiring to redundant racks is an option.

c. All software and programming required for the PLC to operate as a standalone controller is maintained on-board in the processor.  PLCs are programmed with one of the following standard programming languages: 

(1) Ladder Diagrams:  Used primarily for logic (Boolean) operations and is easily understood by electricians and control technicians.  This is the most commonly used language in the United States and is supported by all PLC suppliers.

(2) Function Block Diagrams:  Used primarily for intensive analog control (PID) operations and is available only in “high-end” PLC’s.  It is more commonly used outside the United States.

(3) Sequential Function Chart:  Used primarily for batch control operations and is available only in “high-end” PLC’s.

(4) Structured Text:  Used primarily by PLC programmers with a computer language background and is supported only in “high-end” PLC’s.

d. SCADA PLCs should be specified to be programmed using ladder diagrams.  This language is very common, and duplicates in format traditional electrical schematics, making it largely understandable by electricians and technicians without specific PLC training.

The ladder logic functions the same as equivalent hard-wired relays.  The PLCs in a SCADA system will be networked to one or more central personal computer (PC) workstations, which provide the normal means of human machine interface (HMI) to the system.

These PCs will be provided with Windows-based HMI software that provides a graphical user interface (GUI) to the control system in which information is presented to the operator on graphic screens that are custom-configured to match the facility systems.

For example, the electrical system status may be shown on a one-line diagram graphic in which open circuit breakers are colored green, closed breakers are colored red, and voltage and current values are displayed adjacent to each bus or circuit breaker.

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Bioelectricity: A Quantitative Approach, is the new edition of the classic introductory text to electrophysiology. It covers many topics that are central to the field including:


- electrical properties of the cell membrane
- action potentials
- cable theory
- electrical stimulation
- extracellular waveforms
- cardiac electrophysiology
- function stimulation (FES)

The study of electrophysiology has progressed rapidly because of the precise, delicate, and ingenious experimental studies of many investigators.

The field has also made great strides by unifying these experimental observations through mathematical descriptions based on electromagnetic field theory, electrochemistry, etc., which underlies these experiments. In turn, these quantitative materials provide an understanding of many electrophysiological applications through a relatively small number of fundamental ideas.

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CLASSES OF ANALOG CONTROLLERS TUTORIALS

Analog controllers can be classified by the relationship between the error signal input to them and the
control action they produce:

a. Proportional (P) controllers produce an output that is directly proportional to the error signal.  A defining characteristic of P control is that the error signal must always be non-zero to produce a control action; therefore, proportional control alone cannot return the process to setpoint following an external disturbance.

This non-zero error signal that is characteristic of P controllers is the steady-state offset. The adjustable value of the proportionality constant of a P controller is the gain.  The higher the gain, the greater the control action for a given error signal and the faster the response.

An example of a P controller is a governor on an engine-generator operating in droop mode, in which the governor opens the fuel valve proportionately to the difference between the desired revolutions per minute (RPM) setpoint and actual RPM; as load on the generator increases, RPM decreases and the governor increases the fuel flow to allow the engine to carry the additional load.

Similarly, as load decreases, RPM increases and the governor responds by reducing fuel flow to match the new load condition.  For any condition other than noload, the actual RPM will be slightly different from the setpoint RPM (steady-state offset).

b. Proportional plus Integral (PI) controllers produce a control action that is proportional to the error signal plus the integral of the error signal.  The addition of the integrator allows the controller to eliminate the steady state offset, and return the process variable to the setpoint value.

The adjustable value of the integration constant of the PI controller is called the reset, because it has the effect of resetting the error signal to zero.  An engine governor operating in isochronous mode, in which constant RPM is maintained over the full load range, uses PI control to accomplish this.

c. Proportional plus Integral plus Derivative (PID) controllers add a component of control action that is proportional to the derivative of the error signal, or the rate at which the error signal is changing.

This mode of control allows the controller to anticipate changes in the process variable by increasing control action for rapid changes, making it useful for systems that require very fast response times, or are inherently unstable without the controller.  The adjustable value of the derivative constant in a PID controller is the rate.

Remote Data Acquisition Using Wireless - Scada System White Paper Free PDF Download Link

In this paper we have developed an integrated wireless SCADA system for monitoring &  accessing the performance of remotely situated device parameter such as temperature, pressure, humidity on real time basis.

For this we have used the infrastructure of the existing  mobile network, which is based on GPRS technique Supervisory Control and Data  Acquisition (SCADA) is a field of constant development and research. This project investigates on creating an extremely low cost device which can be adapted to many different SCADA applications via some very basic programming, and plugging in the relevant peripherals.

Much of the price in some expensive SCADA applications is a result of using specialized communication infrastructure. The application of infrastructure, in the proposed scheme the cost will come down. Additionally the generic nature of the device will be assured.

Wireless SCADA deals with the creation of an inexpensive, yet adaptable and easy to use SCADA device and infrastructure using the mobile telephone network, in particular, the General Packet Radio Service (GPRS). The hardware components making up the device are relatively unsophisticated, yet the custom written  software makes it re-programmable over the air, and able to provide a given SCADA application with the ability to send and receive control and data signals at any non predetermined time.

GPRS is a packet-based radio service that enables “always on” connections, eliminating repetitive and time-consuming dial-up connections.  It will also provide real throughput in excess of 40 Kbps, about the same speed as an excellent landline analog modem connection.

From the wireless SCADA system which is proposed in setup the temperature of around 30 deg C could be sufficiently recorded from remote location. In the similar manner reading of electric energy meter could be read 223 Kilo Watt Hour (KWH) or 223 Unit.

The properly designed SCADA system saves time and money by eliminating the need of service personal to visit each site for inspection, data collection /logging or make adjustments.    

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SCADA Systems Security - White Paper Free PDF Download Link

1. Abstract
The purpose of this paper is to define what SCADA systems are and their application in modern  industry and infrastructure, to elucidate the reasons for rising concern over the security of these  systems, to analyze the fundamental vulnerabilities and to put forth recommendations for the  implementation of security in these systems.

2. Introduction:
Supervisory Control and Data Acquisition systems are basically Process Control Systems (PCS), specifically designed to automate systems such as traffic control, power grid management, waste processing etc.

3. Application
Control systems are used at all levels of manufacturing and industrial processing. A  manufacturing plant that employs robotic arms will have a control system to direct robotic arms and conveyor belts on the shop floor. It may use that same system for packaging the finished product and tracking inventory. It may also use a control system to monitor its distribution network.

A chemical company will use control systems to monitor tank levels and to ensure that ingredients are mixed in the proper proportions. A Las Vegas casino will use control systems to direct the spray from water fountains in coordination with the lights and music. Control systems are also used in the drilling and refining of oil and natural gas. They are used in the distribution of water and electricity by utility companies, and in the collection of wastewater and sewage. Virtually every sector of the economy employs control systems at all levels.

The term "supervisory control and data acquisition" (SCADA), however, is generally accepted to
mean the systems that control the distribution of critical infrastructure public utilities (water,
sewer, electricity, and oil and gas).

SCADA systems are still to come into widespread infrastructural use in India. In this country they
are being used primarily for automation in industrial production, and to some extent for
specialized process control.  Ranbaxy Labs
1 and Voltas
2 are two of the companies in India using  SCADA systems for process control.


However, they are increasingly common in the US, UK, Australia to name a few countries, where
they are used in the control of infrastructural systems such as power, water and waste
management, traffic control etc. The economy and infrastructure of these countries is increasingly
dependant on SCADA systems.

4. Implementation: How do they work?
3. SCADA systems are primarily control systems. A typical control system consists of one or more
remote terminal units (RTU) connected to a variety of sensors and actuators, and relaying
information to a master station. Figure 1 illustrates this generic, three tiered approach to control
system design. Figure 2 shows a typical RTU.

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