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Zone4info - Connections for Testing the Resistance Between the Low Voltage Winding and Ground
Connections for Testing the Resistance Between the Low Voltage Winding and Ground Posted by Ackerley Acton Fri at 10:54 PM
Connections for Testing the Resistance Between the Low Voltage Winding and Ground The connections for testing the insulation resis-tance between the low voltage winding and ground are illustrated in Figure 8-18. One test lead is connected to the earth (-) terminal of the megohmmeter and to a transformer case ground. Another test lead is connected to the line (+) terminal of the megohmmeter and to the low voltage (X) terminal of the transformer. A lead is also connected between the guard (G) terminal of the megohmmeter and the high voltage (H) terminal of the transformer to divert current that leaks to the high voltage winding so that this leakage current is not measured
Connections for Testing the Resistance Between the Low Voltage Winding and the High Voltage Winding The connections for testing the resistance between the low voltage winding and the high voltage winding are illustrated in Figure 8-19. One test lead is connected to the earth (-) terminal of the megohmmeter and to the high voltage (H) terminal of the transformer. Another test lead is connected to the line (+) terminal of the megohm-meter and to the low voltage (X) terminal of the transformer. A lead is also connected between the guard (G) terminal of the megohmmeter and a transformer case ground to divert current that leaks to ground so that this leakage current is not measured.
Connections for Testing the Insulation Resistance Between the Transformer Core and Ground A transformer core to ground test is a type of insulation resistance test that is typically performed after a transformer has been moved or after any work has been done inside a transformer. As illus-trated in Figure 8-20, a core ground connects the core that the windings are wound around to the is no current flow. Circuit breakers are designed to take advantage of these momentary absences of current flow to help extinguish arcs. Brought By: Electrical Engineering Design (Electrical-ed.com)
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Reference: Substation Operation and Maintenance
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Zone4info - Current Transformers
Current Transformers Posted by Electrical Engineering Design Thu at 10:09 PM
Current Transformers In contrast to potential transformers, which reduce line voltage, current transformers reduce line current to a proportionally lower current for metering or relaying. Current transformers can look like potential transformers or surge arrestors. One identifying feature on the current transformer shown in Figure 1-36 is a large canister on top of the bushing with a conductor are not always forced-oil/forced-air cooled. Power transformers with other kinds of cooling systems can also be gas sealed. Figure 3-36 shows a gas-sealed, self-cooled/forced-air-cooled power transformer. The cooling system is recognizable by the combination of the radiator and the fan. Regardless of the type of cooling system that a gas-sealed power transformer has, the gas seal system works in basically the same way. The simpli-fied illustration in Figure 3-37 represents the sealing system of a gas-sealed power transformer. The components of the sealing system are a gas cylinder, two pressure regulators, two gauges, and a pressure relief device
The windings in a gas-sealed power transformer are completely covered by oil. The rest of the enclosure is filled with gas, which is supplied through tubing from the cylinder. The regulators ensure that gas is supplied at a pressure slightly above atmospheric pressure. This slight positive pressure keeps air and moisture from leaking into the enclosure. When the transformer is operating, the windings heat the oil, causing it to expand. As the expanding oil compresses the gas, the pressure inside the enclosure increases. If the pressure rises enough to exceed a predetermined high value, the relief device releases gas from the transformer enclosure to atmosphere. The release of gas continues until pressure returns to an acceptable value. When the transformer becomes cooler, for example, during a period of reduced load, the oil also becomes cooler, and it contracts. As the oil contracts, the pressure inside the transformer enclosure drops. If the pressure falls below a prede-termined low value, a regulator adds gas from the cylinder to the enclosure until the pressure returns to an acceptable value. The regulators and the relief device in a gas-sealed power transformer regulate gas flow. The gauges indicate pressure. For example, the gauge shown in Figure 3-38 indicates the pressure inside the gas cylinder. As gas in the cylinder is used, the cylinder pressure drops. A low pressure reading means that the gas is running out, and the cylinder may need to be replaced.
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Next, both selector switch A and selector switch B are rotated clockwise, so that selector switch B slides over to tap 2, and selector switch A slides across tap N to the opposite end of the tap. (Selector switch A remains on tap N.) Since current is not flowing through selector switch B, there is no arcing as the switch changes taps. Then, transfer switch B is closed, so that current flows across the reversing switch and the raise tap, labeled R, from left to right through a portion of the tapped winding, across tap 2 and selector switch B, across transfer switch B, and out lead X0. Current continues to flow across the neutral tap, across selector switch A, across transfer switch A, and out lead X0. Transfer switch A is then opened to interrupt current flow through selector switch A. Both selector switch A and selector switch B are rotated clockwise, so that selector switch A slides over to tap 2, and selector switch B slides across tap 2 to the opposite end of the tap.
Once selector switch A is on tap 2, transfer switch A is closed, so that current again flows across selector switch A and transfer switch A and out lead X0. This completes the tap change. The new tap position is shown in Figure 4-18. With the reversing switch in the Raise position and the selector switches on tap 2, a portion of the tapped winding is added to the secondary winding. This changes the ratio of secondary turns to primary turns and effectively raises the secondary voltage. The first tap position that adds turns to the secondary winding is called oneraise. As the selector switches are moved clockwise to the other taps, turns are added to the secondary to raise the secondary voltage. When all of the tapped windings are added, the tap changer is at the full-raise position. To lower the secondary voltage, the selector switches are rotated counterclockwise back to the neutral tap. Then, the reversing switch slides from the Raise position (R) to the Lower position (L), and the selector switches rotate counterclockwise from tap N to tap 4. When the reversing switch is in the Lower position, and the selector switches are on tap 4, current flows from left to right across the secondary winding, across the reversing switch and the Lower tap, from right to left through part of the tapped winding, across tap 4 and the selector switches, across the transfer switches, and out lead X0. Brought By: Electrical Engineering Design (Electrical-ed.com)
Reference: Substation Operation and Maintenance
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Zone4info - Explanation of Demand Charges
Explanation of Demand Charges Posted by Brown John October 6
Explanation of Demand Charges Depending on how they use electricity, electric utility customers are charged for different electric services. Along with a basic customer charge – which is a set fee paid monthly or seasonally – most customers pay for the energy they use (measured in kilowatt-hours, abbreviated kWh). Larger users of electricity are also charged for something called demand (measured in kilowatts, abbreviated kW). In order to explain electric demand, we can look at a similar kind of situation. Suppose we want to find out the maximum amount of water that will be flowing in a stream in the coming month. We can hang a flat board in the stream and fasten it in such a way as to swing up when more water is flowing. Then we figure out a way to get the board to “hang up” so it won’t swing back down when the water level drops back down. This will give us an idea of the highest flow since we last let the board swing down. The board measures the peak flow of the stream. The electric utility uses demand meters that measure flowing electricity as the board in the above example measures flowing water. Demand meters register the highest rate of electrical flow (or current) during a billing period. It’s actually a little more complicated than that, because the meter records an average flow for every 15 minute interval. The customer is billed for the highest average 15 minute flow during the billing period. So how does the demand affect the customer’s electric bill? The demand charge will be a large part of the bill if the customer uses a lot of power over a short period of time, and a smaller part of the bill if the customer uses power at a more or less constant rate throughout the month. Let’s look at two examples: 1. A customer runs a 50 horsepower (hp) irrigation pump for only five hours during July1: Demand Charge = 50 hp x .746 kW/hp x $8.03/kW = $299.52 Energy Charge = 50 hp x .746 kW/hp x 5 Hr x $0.034/kWh = $6.34 2. The same customer runs a 50 hp irrigation pump constantly through the entire month of July: Demand Charge = 50 hp x .746 kW/hp x $8.03/KW = $299.52 Energy Charge = 50 hp x .746 kW/hp x 744 Hr x $0.034/kWh = $943.54 As you can see, the demand charge portion of the customer’s power bill does not change, whether the pump runs fifteen minutes or all month. However, the energy charge portion of the power bill does depend on the amount of time the pump runs. So a customer who is careful and doesn’t run the pump more hours than necessary will save money on the energy bill.
How can you save money on your demand charge? • Make sure your motor is the correct size for your pump. An oversized motor could be increasing your demand and costing you money. It’s also possible that a newer, more efficient pump and motor combination may be available that would save on demand and energy. • Make sure your pump and motor combination is the correct size for your system. If you are using a 75 hp pump when a 50 hp pump would do the job, you are wasting 25 hp or 18.7 kW of demand. (25 hp x .746 kW/hp = 18.7 kW) • Make sure that worn pumps, motors, nozzles, and leaks are not increasing flow to the point where demand has increased. You can get an idea of what your demand should be by multiplying the total connected horsepower on your meter by .746 kW/hp. This should be approximately the demand amount on your utility bill. Be aware that your pivot drive and the end gun booster pump will increase your demand. • Be aware of when your meter is read each month. If you only run your pump for a day or two during a billing period (for example, at the beginning or end of the year) your demand cost could far exceed your energy cost. These examples assume a rate of $8.03 for every kW of demand and also assume a rate of $0.034 per kWh of electricity. The actual charges on your power bill may differ.
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Source: http://www.northwesternenergy.com
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Zone4info - Voltage Unbalance/Single-Phasing
Voltage Unbalance/Single-Phasing Posted by Johan column October 5
Voltage Unbalance/Single-Phasing 1. 2. 3. 4. 5. 6. 7. 8.
1. 2. 3. 4. 5.
Historically, the causes of motor failure can be attributed to: Overloads 30% Contaminants 19% Single-phasing 14% Bearing failure 13% Old age 10% Rotor failure 5% Miscellaneous 9% 100% From the above data, it can be seen that 44% of motor failure problems are related to HEAT. Allowing a motor to reach and operate at a temperature 10°C above its maximum temperature rating will reduce the motor’s expected life by 50%. Operating at 10°C above this, the motor’s life will be reduced again by 50%. This reduction of the expected life of the motor repeats itself for every 10°C. This is sometimes referred to as the “half life” rule. Although there is no industry standard that defines the life of an electric motor, it is generally considered to be 20 years. The term, temperature “rise”, means that the heat produced in the motor windings (copper losses), friction of the bearings, rotor and stator losses (core losses), will continue to increase until the heat dissipation equals the heat being generated. For example, a continuous duty, 40°C rise motor will stabilize its temperature at 40°C above ambient (surrounding) temperature. Standard motors are designed so the temperature rise pro-duced within the motor, when delivering its rated horsepower, and added to the industry standard 40°C ambient temperature rating, will not exceed the safe winding insulation temperature limit. The term, “Service Factor” for an electric motor, is defined as: “a multiplier which, when applied to the rated horsepower, indi-cates a permissible horsepower loading which may be carried under the conditions specified for the Service Factor of the motor.” “Conditions” include such things as operating the motor at rated voltage and rated frequency. Example:A 10 H.P. motor with a 1.0 S.F. can produce 10 H.P. of work without exceeding its temperature rise requirements. A 10 H.P. motor with a 1.15 S.F. can produce 11.5 H.P. of work without exceeding its temperature rise requirements. Overloads, with the resulting overcurrents, if allowed to con-tinue, will cause heat build-up within the motor. The outcome will e the eventual early failure of the motor’s insulation. As stated previously for all practical purposes, insulation life is cut in half for every 10°C increase over the motor’s rated temperature. Voltage Unbalance When the voltage between all three phases is equal (balanced), current values will be the same in each phase winding. The NEMA standard for electric motors and generators rec-ommends that the maximum voltage unbalance be limited to 1%. When the voltages between the three phases (AB, BC, CA) are not equal (unbalanced), the current increases dramatically in the motor windings, and if allowed to continue, the motor will be damaged. It is possible, to a limited extent, to operate a motor when the voltage between phases is unbalanced. To do this, the load must be reduced. Voltage Unbalance Derate Motor to These in Percent Percentages of the Motor’s Rating*
Some Causes of Unbalanced Voltage Conditions •Unequal single-phase loads. This is why many Some Causes of Unbalanced Voltage Conditions •Unequal single-phase loads. This is why many consulting engineers specify that loading of panelboards be balanced to ±10% between all three phases. •Open delta connections. •Transformer connections open - causing a single-phase condition. •Tap settings on transformer(s) not proper. •Transformer impedances (Z) of single-phase transformers connected into a “bank” not the same. •Power factor correction capacitors not the same. . .or off the line.
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Insulation Life The effect of voltage unbalance on the insulation life of a typical T-frame motor having Class B insulation, running in a 40°C ambient, loaded to 100%, is as follows
Note that motors with a service factor of 1.0 do not have as much heat withstand capability as does a motor that has a service factor of 1.15. Older, larger U-frame motors, because of their ability to dissi-pate heat, could withstand overload conditions for longer periods of time than the newer, smaller T-frame motors.
Insulation Classes 1. 2. 3. 4.
The following shows the maximum operating temperatures for dif-ferent classes of insulation. Class A Insulation 105°C Class B Insulation 130°C Class F Insulation 155°C Class H Insulation 180°C How to Calculate Voltage Unbalance and the Expected Rise in Heat
Step 1:Add together the three voltage readings: 248 + 236 + 230 = 714V Step 2:Find the “average” voltage. 714 /3 = 238V Step 3:Subtract the “average” voltage from one of the voltages that will indicate the greatest voltage difference. In this example: 248 – 238 = 10V Step 4: 100 x greatest voltage difference / average voltage = 100 x 10 / 238 = 4.2 percent voltage unbalance Step 5:Find the expected temperature rise in the phase winding with the highest current by taking. . . 2 x(percent voltage unbalance)^2 In the above example: 2 ≈(4.2) ^2 = 35.28 percent temperature rise. Therefore, for a motor rated with a 60°C rise, the unbalanced voltage condition in the above example will result in a temperature rise in the phase winding with the highest current of: 60°C ≈135.28% = 81.17°C Prepared By Zone4info.com Team Source: www.bussmann.com
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Zone4info - Short-Circuit Withstand Ratings
Short-Circuit Withstand Ratings Posted by Ackerley Acton October 5
Protecting The Electrical Distribution System “Normal” and “overload” conditions … “fault current”…”interrupt” versus “withstand” ratings…”current-limiting.” Knowing what these terms mean and applying them correctly is fundamental to designing safe, reliable electrical distribution systems. This is especially true in light of more stringent code enforcement and the current design trend to deliver energy savings by selecting low-impedance transformers. Why? Lower transformer impedances mean higher short-circuit currents. Simply choosing a circuit breaker with a high interrupt rating won’t assure adequate protection under short-circuit conditions. With an “ounce of prevention,” you can avoid the code official’s “red tag” at your next system start-up. Let’s review the meaning of the terms that opened this article, define some of the issues related specifically to HVAC motor starter applications and identify practical, effective solutions.
Normal Operation, n. conditions” to select overcurrent protection devices such as circuit breakers and fuses. Rating factors are applied, based on the type and number of connected loads, to assure that the devices selected adequately protect the motor as it starts and while it’s running. Let’s look at an example. Suppose a 500-ton chiller has a 480-volt motor that draws 400 amps at rated load conditions. The electrical distribution system includes a wye-delta starter powered by a 1,500-kVA transformer. Operating “normally,” the chiller motor draws about 800 amps during the 4 seconds it takes to start; then 400 amps or less at running speed The size of the interconnecting wires between the transformer and starter reflects the type and rated amperage draw of th e load, i.e. the chiller motor. Sizing the wires on this basis assures that they can carry the inrush current at start-up without overheating.
Overload Operation, than its rated amperage for an extended period. Basic overl oad devices simply open the circuit when current draw reaches the “trip” point. More sophisticated devices attempt to restore normal motor operating conditions by reducing the load, but will disconnect the motor if overloading persists. For most overload protection devices, “trip” time is determined by the magnitude of the overload. Figure illustrates a straight-line, time/current “trip” curve that shows response times for current draws greater than 110 percent of RLA. A device with these characteristics would allow our example chiller motor to draw 480 amps for 8 seconds before disconnecting it. Fault Current Imagine a wrench inadvertently left in a starter following service. Touching two terminals, it completes the circuit between them when the panel is energized. What results is a potentially dangerous situation or “fault condition” caused by the low-impedance, phase-to-phase or phase-toground connection … a “short circuit. Fault current, also called “short-circuit current” (Isc ),describes current flow during a short. It passes through all components in the affected circuit. Fault current is generally very large and, therefore, hazardous. Only the combined impedance of the object responsible for the short, the wire, and the transformer limits its magnitude. One objective of electrical distribution system design is to minimize the effect of a fault, i.e. its extent and duration, on the uninterrupted part of the system. Coordinating the sizes of circuit breakers and fuses assures that these devices isolate only the affected circuits. Put simply, it prevents a short at an outlet from shutting down power to the entire building! Calculating the magnitude of short-circuit current is prerequisite to selecting appropriate breakers and fuses. If the distance between transformer and starter is brief, the calculation can be simplified by ignoring the impedance of the interconnecting wiring … a simplification that errs on the side of safety. We can also assume that the source of the fault has zero impedance, i.e. a “bolted” short. Given
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these assumptions, the only impedance left to consider is that of the transformer. (Impedance upstream of the transformer is usually negligible.) Suppose the 1,500-kVA transformer in our example has impedance of 5.75 percent. With this value and the equation below, we can determine how much fault current a short circuit will produce. As you can see, a short would force our wiring to carry more than 30,000 amps when it was designed to handle only 400 amps!
Short-circuit current is often two orders of magnitude greater than normal operating current. Unless a circuit breaker or fuse successfully interrupts the fault, this enormous amperage rapidly heats components to very high temperatures that destroy insulation, melt metal, start fires … even cause an explosion if arcing occurs. The inherent likelihood of severe equipment and property damage, as well as the risk of personal injury or death, underscores the importance of sufficient electrical distribution system protection
Interrupt Rating Determined under standard conditions, the “interrupt rating” specifies the maximum amount of current a protective device can cut off safely… i.e. without harm to personnel or resulting damage to equipment, the premises or the device itself. For example, a circuit breaker that trips “safely” successfully interrupts the fault, can be reset and will function properly afterward. To safely stop the fault current calculated for our chiller-motor scenario, the interrupt rating of the circuit breaker or fuses selected must be at least 31,400 amps. Before leaving this topic, let’s dispel a common misconception: “An overcurrent protection device with a comparatively high interrupt rating limits current to other components.” Not so—not unless it’s also a true current-limiting device as described on page 3. Even though the device successfully breaks the circuit, all components in the circuit will be exposed to the full magnitude of fault current (as well as the severe thermal and magnetic stresses that accompany it) for the time it takes the device to respond.
Withstand Rating Though often confused, “interrupt rating” and “withstand rating” are not interchangeable terms. Unlike the interrupt rating, which defines the performance limit of an overcurrent protection device (e.g. circuit breaker or fuse), the “withstand rating” is a performance limit for an enclosure. In other words, it identifies the maximum short-circuit amperage an enclosure can contain without injuring personnel or damaging the premises. Underwriters Laboratories Inc. (UL) defines the short-circuit test methods and parameters for HVAC equipment. Essentially, the test subjects an enclosure to the recommended current, i.e. 4,000 amps if the unit RLA exceeds 40 amps and 3,500 amps if it’s less. If the doors blow open or if it emits flames or sparks, the enclosure fails the test. For those that pass, it’s “acceptable”—even probable— that the internal components will be damaged beyond repair. Given the destructiveness and expense of this test, it’s not surprising that most manufacturers prefer not to pursue higher-than-normal short-circuit withstand ratings for their equipment unless there’s a documented need. Recall that when a fault occurs, all components in the circuit experience the brunt of the short circuit until it’s stopped. Therefore, it’s important to assure that all components “at risk” can withstand a fault condition without causing injury or damaging the surroundings. The National Electric Code (NEC) states this requirement in Section 110-10, “Circuit Impedance and Other Characteristics”: The overcurrent protective devices, the total impedance, the component short-circuit withstand ratings, and other characteristics of the circuit to be protected shall be selected and coordinated to permit the circuit protective devices used to clear a fault to do so without extensive damage to the electrical components of the circuit. This fault shall be assumed to be either between two or more of the circuit conductors, or between any circuit conductor and the grounding conductor or enclosing metal raceway. Commentary in the 1996 National Electrical Code®Handbookfurther explains Section 110-10: Overcurrent protective devices (such as fuses and circuit breakers) should be selected to ensure that the short-circuit withstand rating of the system components will not be exceeded should a short circuit or high-level ground fault occur. System components include wire, bus structures, switching, protection and disconnect devices, distribution equipment, etc., all of which have limited short-circuit ratings and would be damaged or destroyed if these short-circuit ratings are exceeded. Merely providing overcurrent protective devices with sufficient interrupting ratings will not ensure adequate short-circuit protection for the system components. When the available short-circuit current exceeds the withstand rating of an electrical component, the overcurrent protective device must limit the let-through energy to within the rating of that electrical component. To comply with this section of the NEC, all of the component selections in our chiller-motor scenario must be based on a minimum short-circuit withstand rating of 31,400 amps … a requirement well above UL’s standard ratings
Current Limiting All components and wiring in an electrical distribution system offer some degree of resistance. Under normal conditions, the heat produced when current flows against this resistance readily dissipates to the surroundings. However, the enormous current generated during a short circuit produces damaging heat at a much faster rate than can be safely dispersed. Interrupt the current and you stop adding heat to the system. As Figure suggests, time is a critical determinant of the amount of heat (energy) added. An electrical short that lasts three cycles, for example, adds six times the energy of one lasting just one-half cycle. It’s in this sense that all circuit breakers and fuses “limit” current. Figure 2 also shows the effect of a current-limiting device. To be truly current-limiting, the interrupting device must open the circuit within onequarter cycle (1/240 second), i.e. before the fault current peaks. Remember our chiller-motor scenario? If there’s no starter available with a short-circuit withstand rating greater than 31,400 amps, compliance with NEC Section 110-10 requires that we either: nAdd a current limiting device, i.e. usually a fuse, but sometimes a circuit breaker and fuse in series, that restricts the fault current to a value less than the starter’s short-circuit withstand rating. Or … nRedesign the electrical distribution system to reduce the fault current. Choosing this approach warrants a more detailed fault-current analysis. Prepared By: zone4info.com Team Source: The Trane Company’s recycling program
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Zone4info - WYE-DELTA CLOSED
WYE-DELTA CLOSED Posted by Mark David October 3
Y∆CLOSED / NEUTRAL = PRIM NO-SEC NO WHERE USED To supply three-phase loads. No excessive circulating currents when transformers of unequal impedance and ratio are banked. No problem from third harmonic over-voltage or telephone interference. If a ground is required, it may be placed on either an X1 or an X2 bushing as shown.
WYE-DELTA FOR POWER Often it is desirable to increase the voltage of a circuit from 2400 to 4160 volts to increase its potential capacity. This diagram shows such a system after it has been changed to 4160 volts. The previously delta-connected distribution transformer primaries are now connected from line to neutral so that no major change in equipment is necessary. The primary neutral should not be grounded or tied into the system neutral since a single-phase ground fault may result in extensive blowing of fuses throughout the system.
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BANK RATING Maximum safe bank rating for balanced three-phase loads (when transformer kva's are unequal) is three times the kva of the smallest unit. A disabled transformer renders the bank inoperative.
IMPEDANCE & GROUNDING The wye-delta connection is one of the most popular connections used today. Transformers are often connected from delta-delta to wye-delta to take advantage of 1.732 times the delta transmission voltage. In this connection, it is not necessary that the impedance of the three transformers be the same. This connection should not be used with CSP single-phase transformers since when one breaker opens serious unbalancedsecondary voltages may appear. The wye of this systemshould not be grounded because then the bank serves as a grounding bank and will supply ground-fault current for a phase-to-ground fault on the primary system. Also for unbalanced three-phase loads on the primary system, the secondary acts as a balance coil; therefore, circulating current may result in an overload.
STATIC DISCHARGE Potentially present on a non-grounded primary wye connection. A high, excessive voltage results on a 3-phase Y-∆connection on the secondary line to ground when one leg of the primary is open. The voltage present isstatic with no power and bleeds off when taken to ground. This static can damagea volt-ohmmeter. The static is greater when the secondary feeder is short and lesser when the secondary feeder is long. The static problem is resolved by grounding one phase or the center tap of one transformer on the secondary side, but this usually requires special KWH metering. This static condition is present only when a primary line is open, not the secondary. Thisstatic condition can occur on an open (2-transformers) or closed (3-transformers) bank. This static condition can occur with any primary voltage.
FERRORESONANCE Negative effects of ferroresonance are potentially present on non-grounded primary wye connections. There is more danger at 14,400/24.900 VAC and higher. There is more danger with smaller transformers. A rule-of-thumb concerning negative ferroresonance effects is that transformers 25 KVA and smaller at 14,400/24,900 are susceptible to damage. 30 KVA and larger transformers are relatively safe from adverse ferroresonance effects at 14,400/24,900. Higher voltages than 14,400/24,900 would necessitate larger transformers than 30 KVA to be considered inherently safe from adverse ferroresonance effects. On a floating Y-∆connection, temporarily ground the primary neutral when closing or opening primary fuses to avoid adverse ferroresonance effects. A “chain ground” (a fourth or neutral cutout) should be installed and closed while closing or opening the power cutouts and then re-opened after all of the power cutouts are closed. Configurations used to avoid ferroresonance are an open Y-∆with a solidly grounded primary Y or a Y-Y with a solidly grounded primary and secondary Y connection. Read additional information on ferroresonance in the “Transformer Notes” section. Prepared By: zone4info.com Team Source: TRI-STATE ELECTRICALCONTRACTORS, INC
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Zone4info - Negative Sequence Protection
Negative Sequence Protection Posted by Johan column October 2
Negative sequence stator currents, caused by fault or load unbalance, induce double-frequency currents into the rotor that may eventually overheat elements not designed to be subjected to such currents. Series unbalances, such as untransposed transmission lines, produce some negative-sequence current (I2) flow. The most serious series unbalance is an open phase, such as an open breaker pole. ANSI C50.13-1977 specifies a continuous I2 withstand of 5 to 10% of rated current, depending upon the size and design of the generator. These values can be exceeded with an open phase on a heavily-loaded generator. The Basler BE1-GPS100, BE1-951, BE1-1051, or BE1-46N relay protects against this condition, providing negative sequence inverse-time protection shaped to match the short-time withstand capability of the generator should a protracted fault occur. This is an unlikely event, because other fault sensing relaying tends to clear faults faster, even if primary protection fails. Fig. 26 shows the 46 relay connection. CTs on either side of the generator can be used, since the relay protects for events external to the generator. The Basler BE1-46N alarm unit will alert the operator to the existence of a dangerous condition
NEGATIVE-SEQUENCE CURRENT RELAY (46) PROTECTS AGAINST ROTOR OVERHEATING DUE TO A SERIES UNBALANCE OR PROTRACTED EXTERNAL FAULT. NEGATIVE SEQUENCE VOLTAGE RELAY (47) (LESS COMMONLY APPLIED) ALSO RESPONDS. Negative sequence voltage (47) protection, while not as commonly used, is an available means to sense system imbalance as well as, in some situations, a misconnection of the generator to a system to which it is being paralleled Prepared By: Zone4info.com Source: Basler Electric
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Zone4info - Motor Protection
Motor Protection Posted by Ackerley Acton October 2
Overload Protection An overcurrent exists when the normal load current for a circuit is exceeded. It can be in the form of an overload or short circuit. When applied to motor circuits an overload is any current, flowing within the normal circuit path, that is higher than the motor’s normal Full Load Amps (FLA). A short-circuit is an overcurrent which greatly exceeds the normal full load current of the circuit. Also, as its name infers, a short-circuit leaves the normal current carrying path of the circuit and takes a “short cut” around the load and back to the power source. Motors can be damaged by both types of currents. Single-phasing, overworking and locked rotor conditions are just a few of the situations that can be protected against with the careful choice of protective devices. If left unprotected, motors will continue to operate even under abnormal conditions. The excessive current causes the motor to overheat, which in turn causes the motor winding insulation to deteriorate and ultimately fail. Good motor overload protection can greatly extend the useful life of a motor. Because of a motor’s characteristics, many common overcurrent devices actually offer limited or no protection. When an AC motor is energized, a high inrush current occurs. Typically, during the initial half cycle, the inrush current is often higher than 20 times the normal full load current. After the first half-cycle the motor begins to rotate and the starting current subsides to 4 to 8 times the normal current for several seconds. As a motor reaches running speed, the current subsides to its normal running level. Typical motor starting characteristics are shown in Curve 1
Curve 1 Because of this inrush, motors require special overload protective devices that can withstand the temporary overloads associated with starting currents and yet protect the motor from sustained overloads. There are four major types. Each offers varying degrees of protection
Fast Acting Fuses To offer overload protection, a protective device, depending on its application and the motor’s Service Factor (SF), should be sized at 115% or less of motor FLA for 1.0 SF or 125% or less of motor FLA for 1.15 or greater SF However, as shown in Curve 2, when fast-acting, non-timedelay fuses are sized to the recommended level the motors inrush will cause nuisance openings.
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Curve 2 A fast-acting, non-time-delay fuse sized at 300% will allow the motor to start but sacrifices the overload protection of the motor. As shown by Curve 3 below, a sustained overload will damage the motor before the fuse can open.
 Prepared By Zone4info.com Source: Cooper Bussmann www.cooperindustries.com
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Zone4info - Relay, Fuse, and Line Recloser
Relay, Fuse, and Line Recloser Posted by Johan column October 2
Relay, Fuse, and Line Recloser The addition of DR requires that timecoordination is maintained betweenprotective devices on adjacent circuits as the effects of DR on coordination is not limited to the circuit to which it is connected. Faults on an adjacent circuit can cause protective devices on the DR circuit to operate. This is undesirable because service can beinterrupted to customers who would normally be unaffected by this scenario.
The diagramin figure 7 shows that for a fault on distribution circuit 1 there will be fault current contributions from both the substation and the DR. The fault will be sensed by circuit breaker (CB1), circuit breaker (CB2),the 200 amp recloser, and the DR fuses. Normally it is expected that CB1 will clear this fault. However ifthe relay setting for CB1 is too slow there is a possibility that eitherthe recloserorthe DR fuses will operate for this fault. Consider the case of a three phase to ground fault on distribution circuit 1 as shown in The total 3 phase to ground fault current contribution by the DR without the contribution fromthe systemis approximately750 amps. When the DRs are paralleled to the system the contribution decreases to 471 amps as shown in figure . The recloser and the relay characteristics are shown plotted onthe sametime-current scale in figure .
the curves for the CB1 relay and the recloser plotted for total fault current on distribution circuit 1. The plot indicates thatthe recloser will trip before the relayhas a chance to respond. Customers on distribution circuit 2 that are fed beyond the recloser will experience an interruption oftheir electric service and the DRs will also be cleared fromthe system. To correct this coordination problem, the recloser will need to be slower or the CB1 relaysfaster or both. The modified settings will need to be checked for coordination with the other protective devices on this systemfor other fault scenarios. An ideal coordination forall fault conditionsmay not be possible with non-directional overcurrent protective devices. The addition of directional overcurrent relay elements in the recloser and/or at the substation may be needed. Prepared By: zone4info.com Team Reference: IEEE Std. 1547-2003 “IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems.”
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X. H. Chao, "System Studies for DG Projects under development in the US", summary of the panel discussion, IEEE Summer Power Meeting, Vancouver BC, 2001.
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Zone4info - Reclaim the wind, it will work for you
Reclaim the wind, it will work for you Posted by Ackerley Acton October 1
 At a time when more and more taking into account the environment, it is necessary to find the so-called green power source. Besides the photovoltaic panels, which in recent years have experienced a big boom, is another possibility of using wind energy. Developments in the construction and arrangement managed to solve most problems and the negative impact mainly on the population living in close proximity to wind turbines. This article will now briefly justify the use of wind and provide an overview of the most common wind turbines. Contribution was also presented at the international conference NZEE 2012 .  For a relatively stable temperature of the planet is an important balance between energy received and consumed energy. The main source of energy on this planet is the Sun, only a very small way, contributes geothermal energy - see Figure 1 And why wind energy? Two percent of the total input is converted to the wind and the whole TW 3600, which is approximately 1500 times more than the world consumption of electricity in 2010
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Types of wind turbines Wind power has been used already in ancient times mainly for driving sailboats. Great use of wind-powered mills were in Persia, from which then spread throughout the Islamist territory and China. In Europe, windmills were issued in the eleventh century and two decades later became an important tool especially in the Netherlands. The development of western America have contributed greatly wind-powered water pumps, mills and sawmills. Advent of steam engines was the harnessing of wind decreases considerably. The first major wind turbine, built specifically for the production of electricity was produced by Charles Brush in Cleveland, Ohio. Power worked for 12 years from 1888 to 1900 and supplied electricity to his mansion. [1]
Wind turbines with traps These wind turbines are forced to flow in a given direction is simply directed at the surface such as sailboats. It is obvious that the surface on which the wind strikes can not move faster than the wind itself. Old Persian was the turbine turbine with traps, where the vertical axis are fixed horizontal arm and shoulder regions near the vertical wall was built, through which the wind was directed to the turbine blades. Leaning wall wind forcing operate only on one side of the turbine and thus generate torque - see Figure 2a [1]. The best known and easiest modern turbine of this type is called Savoniova turbine - see Figure 2b. The rotation is such that the convex side offers a smaller area for capturing the wind than concave side. For greater efficiency edge blades tend to be a center of rotation and thus allow media flow on the back side. Savoniovy turbines are used as sensors in an anemometer or as starters for turbine with a vertical axis [1, 3].
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Wind turbines Wing The wind lift device generates a force perpendicular to its direction. The best known are wind turbines with horizontal axis (Fig. 3a), are made with a funnel to direct the wind (especially smaller plants with lower performance) or without (large plants with high performance). These turbine rotor blade can move much faster than the actual wind acting on it. Note that driving the propeller shaft, which provides energy, is high above the ground. This requires two types of solutions: either the power generators located at the top of the mast behind the propeller, or power, using long poles with the gears and transferred to a generator, which is located on the ground. The first solution requires a more robust mast and preferred because of mechanical power transmission over long distances is difficult and costly. Install the generator on top of the mast but increases the weight of the whole, which must be rotated to change the direction of the wind. Some wind turbines have a propeller in downstream or upstream air. It was found that the location of the upstream air reduces the noise level around the device. Vertical turbine arrangement just does not allow placement of the generator to the ground, but the system does not need to shoot every time when you change direction - it is a wing turbine with a vertical axis. In Figure 3c shows the wind turbine called Gyromill, the turbine would be able to produce up to 120 kW, was never commercialized. The main disadvantage is the centrifugal force that causes permanent stress on the turbine blades. Elegant way to remove this stress is shaped leaves in the curve rotating rope attached at the top and bottom of the rotating shaft. Turbines with blades shaped curve "troposkin" first proposed by the French engineer Derrieus whereby these turbines are called
Wind turbines operating at Magnus phenomenon At a sufficient distance from the rotating rod is not disturbed air flow, thus moving wind speeds. Once it comes into contact with the bar, the air on one side move in the opposite direction than the direction of the wind, the surface roughness rods causes friction which pulls the air in the direction of its rotation. Speed of the air is the same as the speed of bars and there is a velocity gradient. On the opposite side of the rod accelerates the air in the direction of rotation. The air then flows faster than the wind speed. According to Bernoulli's law higher air velocity on the one hand causes the pressure drop slower than the air on the opposite side and there is a force acting on the rod. The emergence of this force, the result of aerodynamic reactions on a rotating object is called the Magnus effect - viz. Figure 4a. Force is proportional to ω x (Vector), where ω is the angular velocity of the rod and the wind speed. Magnus phenomenon among other things also causes curvature of the ball in baseball. Equipment for the Magnus effect have been designed for low wind speed, work speed from 3 m ∙ s -1 at an average wind speed of 6 m ∙ s -1, the output power of 20 kW and the turbine operates with efficiency greater than 50%
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Authors Joseph Maca, Paul Abraham, Peter Shepherd, University of Technology,
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Zone4info - A proper generator sizing guide line
A proper generator sizing guide line Posted by Mark David September 30
A proper generator sizing guide line Many factors must be considered when determining the proper size or electrical rating of an electrical power generator set. The engine or prime mover is sized to provide the actual or real power in kW, as well as speed (frequency) control through the use of an engine governor. The generator is sized to supply the kVA neededat startup and during normal running operation and it also provides voltage control using a brushless exciter and voltage regulator. Together the engine and generator provide the energy necessary to supply electrical loads in many different applications encountered in today’s society. The generator set must be able to supply the starting and running electrical load. It must be able to pick up and start all motor loads and low power factor loads, and recover without excessive voltage dip or extended recovery time. Nonlinear loads like variable frequency drives, uninterruptible power supply (UPS) systems and switching power supplies also require attention because the SCR switching causes voltage and current waveform distortion and harmonics. The harmonics generate additional heat in the generator windings, and the generator may need to be upsized to accommodate this. The type of fuel (diesel, natural gas, propane, etc.) used is important as it is a factor in determining generator set transient response. It is also necessary to determine the load factor or average power consumption of the generator set. This is typically defined as the load (kW) x time (hrs. while under that particular load) / total running time. When this load factor or average power is taken into consideration with peak demand requirements and the other operating parameters mentioned above, the overall electrical rating of the genset can be deter-mined. Other items to consider include the unique installation, ambient, and site requirements of the project. These will help to determine the physical configuration of the overall system. How to Find the Starting and Running Wattage: Getting the right starting and running wattage of the devices you intend to power is crucial for calculating the accurate power requirements. Normally, you will find these in the identification plate or the owner's manual in the buyer's kit of each respective device, tool, appliance, or other electrical equipment.
Typical rating definitions for diesel gensets are: standby, prime plus 10, continuous and load management (paralleled with or isolated from utility) Any diesel genset can have several electrical ratings depending on the number of hours of operation per year and the ratio of electrical load/genset rating when in operation. The same diesel genset can have a standby rating of 2000 kW at 0.8 power factor (pf) and a continuous rating of 1825 kW at 0.8 pf. The lower continu-ous rating is due to the additional hours of operation and higher load that the continuous genset must carry. These additional requirements put more stress on the engine and generator and therefore the rating is decreased to maintain longevity of the equipment. Different generator set manufacturers use basically the same diesel genset electrical rating definitions and these are based on international diesel fuel stop power standards from organizations like ISO, DIN and others. A standby diesel genset rating is typically defined as supplying varying electrical loads for the duration of a power outage with the load normally connected to utility, genset operating <100 hours per year and no overload capability. A prime plus 10 rating is typically defined as supplying varying electrical loads for the duration of a power outage with the load normally connected to utility, genset operating ≤500 hours per year and overload capability of 10% above its rating for 1 hour out of 12. A continuous rating is typically defined as supplying unvarying electrical loads (i.e., base loaded) for an unlimited time. The load management ratings apply to gensets in parallel operation with the utility or isolated/islanded from utility and these
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ratings vary in usability from <200 hours per year to unlimited usage. Refer to generator set manufac-turers for further definitions on load management ratings, load factor or average power consumption, peak demand and how these ratings are typically applied. Even though there is some standardization of these ratings across the manufacturers, there also exists some uniqueness with regard to how each manufacturer applies their generator sets Electrical rating definitions for natural gas powered gensets are typically defined as standby or continuous with definitions similar to those mentioned above for diesels. Natural gas gensets recover more slowly than diesel gensets when subjected to block loads. Diesel engines have a much more direct path from the engine gov-ernor and fuel delivery system to the combustion chamber and this results in a very responsive engine-generator. A natural gas engine is challenged with air-fuel flow dynamics and a much more indirect path from the engine governor (throttle actuator) and fuel delivery system (natural gas pressure regulator, fuel valve and actuator, carburetor mixer, aftercooler, intake manifold) to the combustion chamber and this results in a less responsive engine-generator. Diesel gensets recover about twice as fast as natural gas gensets. For the actual calculations involved for sizing a genset, there are readily accessible computer software programs that are available on the genset manu-facturer’s Internet sites or from the manufacturer’s dealers or distributors. These programs are used to quickly and accurately size generator sets for their application. The programs take into consideration the many different parameters discussed above, including the size and type of the electrical loads (resistive, inductive, SCR, etc.), reduced voltage soft starting devices (RVSS), motor types, voltage, fuel type, site conditions, ambient conditions and other variables. The software will optimize the starting sequences of the motors for the least amount of voltage dip and determine the starting kVA needed from the genset. It also provides transient response data, including voltage dip magnitude and recovery duration. If the transient response is unacceptable, then design changes can be considered, including oversizing the generator to handle the additional kVAR load, adding RVSS devices to reduce the inrush current, improving system power factor and other methods. The computer software programs are quite flexible in that they allow changes to the many different variables and parameters to achieve an optimum design. The software allows, for example, minimizing voltage dips or using paralleled gensets vs. a single genset. Genset Sizing Guidelines Some conservative rules of thumb for genset sizing include: 1. Oversize genset 20–25% for reserve capacity and for motor starting. 2. Oversize gensets for unbalanced loading or low power factor running loads. 3. Use 1/2 hp per kW for motor loads. 4. For variable frequency drives, oversize the genset by at least 40%. 5. For UPS systems, oversize the genset by 40% for 6 pulse and 15% for 6 pulse with input filters or 12 pulse. 6. Always start the largest motor first when stepping loads. For basic sizing of a generator system, the following example could be used: Step 1: Calculate Running Amperes ■Motor loads: 200 hp motor . . . . . . . . . . . . . 156A 100 hp motor . . . . . . . . . . . . . . 78A 60 hp motor . . . . . . . . . . . . . . . 48A ■Lighting load . . . . . . . . . . . . . . . . 68A ■Miscellaneous loads . . . . . . . . . . 95A ■Running amperes. . . . . . . . . . . 445A Step 2: Calculating Starting Amperes Using 1.25 Multiplier ■Motor loads: . . . . . . . . . . . . . . . . . . . . . . . . 195A . . . . . . . . . . . . . . . . . . . . . . . . . 98A . . . . . . . . . . . . . . . . . . . . . . . . . 60A ■Lighting load . . . . . . . . . . . . . . . . 68A ■Miscellaneous loads . . . . . . . . . . 95A ■Starting amperes. . . . . . . . . . . 516A Step 3: Selecting kVA of Generator ■Running kVA = (445A x 480V x 1.732)/ 1000 = 370 kVA ■Starting kVA = (516A x 480V x 1.732)/ 1000 = 428 kVA Solution Generator must have a minimum starting capability of 428 kVA and minimum running capability of 370 kVA. Also, please see section “Factors Governing Voltage Drop” on generator loading and reduced voltage starting techniques for motors. Generator Set Installation and Site Considerations There are many different installation parameters and site conditions that must be considered to have a successful generator set installation. The following is a partial list of areas to consider when conducting this design. Some of these installation parameters include: ■Foundation type (crushed rock, concrete, dirt, wood, separate concrete inertia pad, etc.) ■Foundation to genset vibration dampening (spring type, cork and rubber, etc.) ■Noise attenuation (radiator fan mechanical noise, exhaust noise, air intake noise) ■Combustion and cooling air requirements ■Exhaust backpressure requirements ■Emissions permitting ■Delivery and rigging requirements ■Genset derating due to high altitudes or excessive ambient temperatures Hazardous waste considerations for fuel, antifreeze, engine oil ■Meeting local building and electrical codes ■Genset exposure (coastal conditions, dust, chemicals, etc.) ■Properly sized starting systems (compressed air, batteries and charger) ■Allowing adequate space for installation of the genset and for maintenance (i.e., air filter removal, oil changing, general genset inspection, etc…) ■Flex connections on all systems that are attached to the genset and a rigid structure (fuel piping, founda-tion vibration isolators, exhaust, air intake, control wiring, power cables, radiator flanges/duct work, etc.) ■Diesel fuel day tank systems (pumps, return piping) ■Fuel storage tank (double walled, fire codes) and other parameters Please see the generator set manufac-turer’s application and installation guidelines for proper application and operation of their equipment Advantages of choosing the right size generator: appropriate size of generator to suit your needs, here's just a few of the benefits obtained by going through that process:
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- No unexpected system failures - No shutdowns due to capacity overload - Increased longevity of the generator - Guaranteed performance - Smoother hassle-free maintenance - Increased system life span - Assured personal safety - Much smaller chance of asset damage Prepared by: zone4info.com Team References: 1. www.eaton.com 2. www.dieselserviceandsupply.com/
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Zone4info - High Voltage Spacing
High Voltage Spacing Posted by Johan column September 27
Introduction How much spacing is needed in high voltage circuits and setups? The general guideline in common use is to allow 7,500 to 10,000 volts, dc per inch in air. When dealing with ac, the general guideline is to multiply the rms voltage by three to determine the spacing that’s required. However, there are techniques to reduce the spacing for both dc and ac. In addition, there are requirements from UL, IEC, and IPC to consider when designing products. Spacing Concerns When evaluating spacing, both clearance and creepage distances need to be addressed. Clearance is the shortest distance between two conductive parts, or between a conductive part and ground, measured through air or other insulating medium. Creepage distance is the shortest distance separating two conductors as measured along the surface touching both conductors. The general guideline of 7,500 to 10,000 volts per inch is affected by the shapes of the conductors. Sharp points will require greater spacing, and large radii surfaces will require less spacing. Arcs or flashover can occur along the surface of some materials at distances much shorter than the flashover distance in air. Therefore, it is extremely important in high voltage designs to look for places where creepage can occur. Factors that affect breakdown voltage besides conductor shape include surface characteristics of insulators and the altitude. If agency approval is needed, there are more rigorous requirements to be addressed. When designing for compliance, additional parameters that must be taken into account include “pollution degree,” “overvoltage category” and “comparative tracking index” (a measure of resistance to surface tracking). For further information on compliance issues, see the articles and industry standards referenced below. Improvements To increase breakdown voltage, the first item to check is the conductor shapes. Although most engineers know that sharp points need to be eliminated, it’s worth a careful look to be sure that the conductor geometry is good. End caps of some components and edges of PCB traces can be particularly troublesome. Large radii can be achieved with the addition of metallic balls and toroid rings Whether operating in air or in an insulating material, spacing can be reduced by addressing the geometry of the conductors, and the electric field gradients. Software is available to analyze the electric field. These analyses can lead to ways to further improve the voltage capability of an assembly. Creepage distances can be increased when conductors cannot be moved by using judiciously placed holes and by using material convolutions. Both creepage and clearance can be improved by encapsulation. Encapsulation can reduce spacing requirements to hundreds of kV/inch, which is more than an order of magnitude better than unencapsulated parts. Of critical importance is obtaining good adhesion. In fact without good adhesion and if conditions are right, breakdown can occur at voltages lower than in air. Other approaches include the use of oil and other insulating liquids and gasses. Examples include transformer oil, silicone oil and sulphur hexafluoride gas. Whether building up a surface to add convolutions, or when using any type of encapsulation, it is generally a good idea to have a continuous, homogeneous insulation system. Under certain conditions, multiple insulation types in series can work, however, it is more difficult to achieve a reliable design. It is also important to keep insulator surfaces clean and dry, since moisture, flux and finger prints can degrade the voltage capability of surfaces. Conclusion Substantial spacing is required for high voltage assemblies and test setups. However, the spacing can be reduced by addressing the geometry and insulation method. For further information, please contact me (see below). This article is for general information only. It is not intended to be used as definitive or official material. For design and practice of high voltage, see industry reference documents, including those from UL and IEC. Prepared By: Zone4info.com Team Source: http://www.highvoltageconnection.com
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Zone4info - Goals of Electrical System Design
Goals of Electrical System Design Posted by Ackerley Acton September 26
Goals of Electrical System Design When considering the design of an electrical distribution system for a given customer and facility, the electrical engineer must consider alternate design approach that best fit the following overall goals. 1- Safety: The No. 1 goal is to design a power system that will not present any electrical hazard to the people who use the facility, and/or the utilization equipment fed from the electrical system. It is also important to design a system that is inherently safe for the people who are responsible for electrical equipment maintenance and upkeep. The National Electrical Code (NEC) NFPA 70 and NFPA 70E, as well as local electrical codes, provide minimum standards and requirements in the area of wiring design and protection, wiring methods and materials, as well as equipment for general use with the overall goal of providing safe electrical distribution systems and equipment. The NEC also covers minimum requirements for special occupancies including hazardous locations and special use type facilities such as health care facilities, places of assembly, theaters and the like and the equipment and systems located in these facilities. Special equipment and special conditions such as emergency systems, standby systems and communication systems are also covered in the code. It is the responsibility of the design engineer to be familiar with the NFPA and NEC code requirements as well as the customer's facility, process and operating procedures, to design a system that protects personnel from live electrical conductor and uses adequate circuit protective devices that will selectively isolate overloaded or faulted circuit or equipment as quickly as possible. 2- Minimum Initial Investment: The owner's overall budget for first cost purchase and installation of the electrical distribution system and electrical utilization equipment will be a key factor in determining which of various alternate system designs are to be selected. When trying to minimize initial investment for electrical equipment, consideration should be given to the cost of installation floor space requirements and possible extra cooling requirements as well as the initial purchase price. 3- Maximum Service Continuity: The degree of service continuity and reliability needed will vary depending on the type and use of the facility as well as the loads or processes being supplied by the electrical distribution system. For example, for a smaller commercial office building a power outage of considerable time, say several hours, may be acceptable, whereas in a larger commercial building or industrial plant only a few minutes may be acceptable. In other facilities such as hospitals, many critical loads permit a maximum of 10 seconds outage and certain loads, such as real time computers, cannot tolerate a loss of power for evern a few cycles. Typically, service continuity and reliability can be increased by: A. Supplying a multiple utility power source or services B. Supplying multiple connection paths to the loads served. C. Using short-time rated power circuit breakers D. Providing alternate customer owned power sources such as generators or batteries supplying uninterruptable power supplies. E Selecting the highest quality electrical equipment and conductors. F. Using the best installation methods G. Designing appropriate system alarms, monitoring and diagnostics H. Selecting preventative maintenance systems or equipment to alarm before an outage occurs. 4. Maximum Flexibility and Expendability: In many industrial manufacturing plants, electrical utilization load are periodically relocated or changed requiring changes in the electrical distribution system. Consideration of the layout and design of the electrical distribution system to accommodate these changes must be considered. For example, providing many smaller transformers or load centers associated with a given area or specific groups of machinery may lend more flexibility for future changes than one large transformer; the use of plug in bus ways to feed selected equipment in lieu of conduit and wire may facilitate future revised equipment layouts
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In addition, consideration must be given to future building expansion, and or increased load requirements due to added utilization equipment when designing the electrical distribution system. In many cases considering transformers with increased capacity or fan cooling to serve unexpected loads as well as including spare additional protective devices and/or provision for future addition of these devices may be desirable. Also to be considered is increasing appropriate circuit capacities or quantities for future growth. Power monitoring communication systems connected to electronic metering can provide the trending and historical data necessary for future capacity growth. 5. Maximum Electrical Efficiency (Minimum Operating Costs) Electrical efficiency can generally be maximized by designing systems that minimize the losses in conductors, transformers and utilization equipment. Proper voltage level selection plays a key factor in this area and will be discussed later. Selecting equipment, such as transformers, with lower operating losses, generally means higher first cost and increased floor space requirements; thus there is a balance to be considered between the owner's utility energy change for the losses in the transformer or other equipment versus the owner's first cost budget and cost of money. 6. Minimum Maintenance Cost: Usually the simpler the electrical system design and the simpler the electrical equipment, the less the associated maintenance costs and operator errors. As electrical system and equipment become more complicated to provide greater service continuity or flexibility, the maintenance costs and chances for operating error increases. The systems should be designed with an alternate power circuit to take electrical equipment (requiring periodic maintenance) out of service without dropping essential loads. Use of draw out type protective devices such as breakers and comibation starters can also minimize maintenance cost and out of service time. 7. Maximum Power Quality The power input requirements of all utilization equipment has to be considered including the acceptable operating range of the equipment and the electrical distribution system has to be designed to meet these needs. For example, what is the required input voltage, current, power factor requirement? Consideration to whether the loads are affected by harmonics (multiples of the basics 60 Hz sine wave) or generate harmonics must be taken into account as well as transient voltage phenomena. The above goals are interrelated and in some ways contradictory. As more redundancy is added to the electrical system design along with the best system design equipment to maximize service continuity, flexibility quality, the more initial investment and maintenance are increase. Thus, the designer must weigh each factor based on the type of facility, the loads to be served, the owner's past experience and criteria. Prepared By: Zone4info.com Team Reference: www.eaton.com
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Zone4info - Low Voltage Switchgear
Low Voltage Switchgear Posted by Ackerley Acton September 24
Low Voltage Switchgear Metal-enclosed low-voltage switchgear is used in many industrial and commercial buildings. These are used as a distribution control center to house the circuit breakers, bus bars, and terminal connections which are part of the power distribution system. Ordinarily, a combination of switchgear and distribution transformers is placed in adjacent metal en-closures, such as that shown in Figure 8-5. This combination is referred to as a load-center unit substation since it is the central control for several loads.
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The rating of these load centers is usually 15,000 volts or lower for the high-voltage section and 600 volts or less for the low-voltage section. Load centers provide flexibility in the electrical power distribution design of industrial plants and commercial buildings. Metal-enclosed switchgear or metal-clad switchgear is a type of equipment which houses all the necessary control devices for the elec-trical circuits that are connected to them.
The control devices contained inside the switchgear include circuit breakers, disconnect switches, inter-connecting cables and buses, transformers, and the necessary measuring instruments. Switchgear is used for indoor and outdoor applications at industrial plants, commercial buildings, and at substations. The voltage ratings of switchgear are usually from 13.8 to 138 kilovolts with 1 mega-volt-ampere to 10 megavolt-ampere power ratings. Prepared By: Zone4info.com Team Source: Power System Distribution
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Zone4info - Importance of busbars
Importance of busbars Posted by Johan column September 23
Importance of busbars Busbars are the most important component in a distribution network. They can be open busbars in an outdoor switch yard, up to several hundred volts, or inside a metal clad cubicle restricted within a limited enclosure with minimum phase-to-phase and phase-to-ground clearances. We come across busbars, which are insulated as well as those, which are open and are normally in small length sections interconnected by hardware. They form an electrical ‘node’ where many circuits come together, feeding in and sending out power
From the above diagram, it is very clear that for any reason the busbars fails, it could lead to shutdown of all distribution loads connected through them, even if the power generation is normal and the feeders are normal. The important issues of switchgear protection can be summarized as: • Loss very serious and sometimes catastrophic • Switchgear damaged beyond repair • Multi-panel boards not available ‘off-the-shelf’ • Numerous joints • Air enclosure • Dust build-up • Insect nesting • Ageing of insulation • Frequency of stress impulses • Long earth fault protection tripping times.
Busbar protection Busbars are frequently left without protection because: • Low susceptibility to faults – especially metal clad switchgear • Rely on system back-up protection • Too expensive and expensive CT’s • Problems with accidental operation – greater than infrequent busbar faults • Majority of faults are earth faults – limited earth fault current – fast protection not required. However, busbar faults do occur.
The requirements for good protection The successful protection can be achieved subject to compliance with the following:
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• Speed – Limit damage at fault point – Limit effect on fault stability • Selectivity – Trip only the faulted equipment – Important for busbars divided into zones • Stability – Not to operate for faults outside the zone – Most important for busbars – Stability must be guaranteed • Reasons for loss of stability – Interruption of CT circuits – imbalance – Accidental operation during testing • Tripping can be arranged ‘two-out-of-two’ – Zone and check relays.
Busbar protection types • Frame leakage • High-impedance differential • Medium-impedance biased differential • Low-impedance biased differential • Busbar blocking.
Frame leakage protection This involves measurement of fault current from switchgear frame to the earth. It consists of a current transformer connected between frames to earth points and energizes an instantaneous ground fault relay to trip the switchgear. It generally trips all the breakers connected to the busbars. Care must be taken to insulate all the metal parts of the switchgear from the earth to avoid spurious currents being circulated. A nominal insulation of 10 Ωto earth shall be sufficient. The recommended minimum setting for this protection is about 30% of the minimum earth fault current of the system
Differential protection This requires sectionalizing the busbars into different zones
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BMID single phase circuit – internal
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Stability characteristic busbar protection High-impedance bus zone Advantages • Relays relatively cheap – offset by expensive CTs • Simple and well proven • Fast – 15–45 ms • Stability and sensitivity calculations – easy providing data is available • Stability can be guaranteed. Disadvantages • Very dependent on CT performance • CT saturation could give false tripping on through faults • Sensitivity must be decreased • DC offset of CTs unequal – use filters • Expensive class X CTs – same ratio – Vknp= 2 times relay setting • Primary effective setting (30–50%) • Limited by number of circuits • Z-earthed system difficult for earth fault • Duplicate systems – decreased reliability • Require exact CT data • Vknp, Rsec , imag, Vsetting • High voltages in CT circuits (±2.8 kV) limited by volt-dependent resistors. Retrofitting • Additional CTs six per circuit • Space problems on metal clad switchgear • Long shutdowns • CT performance important • Class X • Vknp= 2 times setting • Rsec must be low • Limit on number of circuits • CT polarity checks required • Primary injection tests required • Compete switchboard • Separate relay cubicle • Differential relays • Auxiliary relays • CT cabling • Busbar tripping cabling. Biased medium-impedance differential Advantages • High speed 8–13 ms • Fault sensitivity ±20% • Excellent stability for external faults
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• Normal CTs can be used with minimal requirements 240Practical Power Systems Protection • Other protection can be connected to same CTs • No limit to number of circuits • Secondary voltages low (medium impedance) • Well proven 10 000 systems worldwide • Any busbar configuration • No need for duplicate systems • Retrofitting easy • No work on primary CTs • Biasing may prevent possibility of achieving a sensitive enough earth fault setting of Z-earthed systems. Disadvantages • Relays relatively expensive • Offset by minimal CT requirements • Relays with auxiliary CTs require a separate panel.
Low-impedance busbar protection Principle: Merz-price circulating current biased differential CT saturation detector circuits (inhibit pulses) (see Figure 16.10). On through-fault, one CT may saturate – does not provide balancing current for other CT. Spill current (i1– i2), then flows through the operating coil. Electronics detect CT saturation – shorts out differential path. Inhibit circuit only allows narrow spikes in differential coil. Relay stable
Low-impedance busbar protection
Saturation detectors The CTs feed the differential circuit via auxiliary transformers, which in turn feed a typical saturation detector circuit shown in Figure • A voltage Vc is developed across the resistor R • Capacitor C is charged to the peak value of that voltage • A comparator compares voltage with 0.5 V stored in capacitor • On saturation, V drops below 0.5 V capacitor voltage • Comparator then turns on electronic switch across buswires • Pulse width increases with optimum philosophy.
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Saturation detectors
Busbar blocking system Advantages • Very low or no cost system • Simple • Faster than faults cleared by back-up relays • Covers phase and earth faults • Adequate sensitivity – independent of no. of circuits • No additional CTs • Commissioning is simple – no primary current stability tests Disadvantages • Only suitable for simple busbars • Additional relays and control wiring for complex busbars • Beware motor in-feeds to busbar faults • Sensitivity limited by load current. Retrofitting • Easy – if starting contacts available, if not they need to be added • Modern microprocessor relays have starters • No need to work on CTs • Most work is done with system operational • Final commissioning requires very short shutdown. Injection to prove stability between up- and downstream relays.
Busbar blocking scheme Prepared By Zone4info.com Team Source: Practical Power System Protection
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Zone4info - Advantages of HVDC transmission system technology
Advantages of HVDC transmission system technology Posted by Mark David September 22
Advantages of HVDC transmission system technology In general, HVDC transmission and AC transmission can be compared considering three main factors: economic consideration, technical performance and reliability. These three factors can demonstrate the advantages of HVDC over HVAC.
Costs of an HVDC system Bulk power transmission over long distances with HVDC is usually cheaper than with AC. According to Padiyar (2005) costs of transmission generally include capital investment and operational costs. Investment in Right of Way (RoW), transmission pylons, conductors, insulators and terminal equipment are considered as capital investment and the costs of power losses are normally included in operational costs. Since, features of insulators are related to the voltage level, their costs seem to be the same for the certain voltage level in both HVDC and HVAC. As far as the costs of transmission pylons, conductors and RoW are concerned, Kim et al (2009) illustrate that HVDC can transmit the same power with sometimes one and commonly two conductors of the same size and smaller and cheaper pylons, which HVAC transmits with three conductors, expensive and larger pylons see Figure . It can reduce the cost of RoW and conductors in HVDC. They also have noted that construction of a single circuit DC above 1600 MV capacity was not reported until 2008 and it might be because of potential losses in such a high capacity circuit (Kim et al, 2009:3-4). As it is mentioned before one of the main parts of operational costs can be costs of power losses. It has been claimed (Padiyar, 2005) that the costs of losses in HVDC may reduce to about 67% of the AC with the same parameters. It is because of fewer numbers of conductors and absence of skin effect in cables in DC. However, this might happen just over long distance transmission (Padiyar, 2005). As Figure 6 shows, the costs of transmission vary with distance and for short distances of less than ‘break even’, which
may vary between 500-800 km for overhead lines and can be about 450 km in the case of undersea cables, AC seems to be more economical than DC but for distances longer than ‘break even’, AC is more expensive. Lucas (2001) demonstrates the relationship between the possible amounts of power which can be transmitted via a single phase DC power transmission system compared to AC system through the same conductor size by deriving the following equation representing the power ratio for both transmission systems.
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Where Pd is power transmitted by DC and Pa is power transmitted by AC. In practice, AC transmission is either single or double three-phase circuits having 3 or 6 conductors respectively where the above ratio must be multiplied by 2/3 or by 4/3. He also derives the equation for the ratio of conductor cross-section Ad over Aa assuming that the same power is transmitted by both DC and AC transmission systems with the same losses and same peak voltage. This equation can represent the reduction of conductor cross-section in DC transmission system. The equation is as follows.
The equation shows that in the same preset condition the amount of copper used at unity power factor for an AC power transmission system is two times more than for a DC one and at 0.8 lag it is about three times. This equation also illustrates the effect of power factor on the ratio (Lucas, 2001:185-186). The above explanation proves that HVDC is cheaper than HVAC for the distances of more than ‘break-even’ but it is expensive for distances less than that, which is due to the high cost of terminal equipment for conversion in both ends. However, this topic can be further explored by including the topics related to the economic aspects of power systems such as reduction in reserve capacity, environmental benefits etc but that is outside of the word limit of this report. Tables 1-4 from Kim et al (2009) have been added to the appendix for more information on AC and DC systems’ costs.
Technical performance HVDC is likely to have more positive technical characteristics than AC and may overcome some of AC’s problems. According to Sood (2004) through HVDC, full control over power is possible which gives a better control ability to operators for fault current and it heightens transient and dynamic stability of the power system, which can be harder in AC. Over long distance transmission, voltage control is harder in AC due to an increase in line inductance that causes more voltage drop and line compensation (reactive power control) is required whereas in HVDC the voltage profile seems flat and line compensation is not required. One of the major problems of AC could be asynchronous interconnection but as Breuer et al (2004) mention, in the USA and Canada there are many asynchronous power systems, which are interconnected with the help of HVDC. HVDC system is considered more stable then AC. Lucas (2001) clarifies the benefits of HVDC in term of stability by stating that the length of DC link is not governed by stability because DC link is asynchronous by its nature and the way it operates so AC system connected to it does not have to be synchronised with the link. He adds that for AC links to operate in stable condition, the phase angle between sending end and receiving end should not exceed 30º at full-load, however in theory the maximum steady state limit is 90º. He claims that the afore mentioned phase angle shift in the case of 50 Hz frequency is about 0.06º/km and based on this the maximum permissible length without compensation will be 500 km which can be increased to 1000 km with compensation. The issues related to technical performance of HVDC discussed in this section shows that HVDC has a degree of advantage over AC in terms of stability, power flow control and asynchronous interconnection. Prepared By: Zone4info.com Team Source: HVDC System Analsysi by Mohammad Amin Amin
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Zone4info - Applications of Neutral Displacement Relay
Applications of Neutral Displacement Relay Posted by Brown John September 20
Neutral displacement detection can be applied in either of the following situations To initiate an alarm for a single phase to earth fault on an insulated neutral system With such a system an earth fault on one phase will cause the voltages on the other 2 phases to rise with respect to earth and can reach the phase-to-phase voltage. The relay is to be connected across a secondary open delta winding of a 3 phase, 5 limb, voltage transformer which has the primary star point earthed. The voltage across the open delta secondary will rise from zero (or near zero depending on voltage balance) to as high as 3 times the secondary winding voltage per phase, e.g. 63.5V windings will produce up to 190V across the relay for a phase to earth fault close to the VT. B37 relays are rated to withstand this. To effect tripping on earthed neutral systems When the upstream protection isolates an earth fault on a feeder on a delta connected HV side of a power transformer, the possibility remains of voltage rise on the two sound phases if the feeder continues to be energized from the LV side of the power transformer. The residual voltage of the feeder operates the relay at the transformer end of the HV feeder and the relay trips the LV circuit breaker. When the HV windings of the power transformer are delta connected, or star connected with the neutral not available, the neutral displacement protection requires the same equipment as described for the first application above When the HV windings are star connected with the neutral available then the relay can be energized from a single phase voltage transformer having its primary connected between the neutral and earth. Either scheme can be supplemented by a definite time delay relay if required. Prepared By: Zone4info.com Team Source: www.easunreyrolle.com
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Zone4info - Introduction to Photovoltaic Systems
Introduction to Photovoltaic Systems Posted by Mark David September 20
Introduction Photovoltaic offer consumers the ability to generate electricity in a clean, quiet and reliable way. Photovoltaic systems are comprised of photovoltaic cells, devices that convert light energy directly into electricity. Because the source of light is usually the sun, they are often called solar cells. The word photovoltaic comes from "photo" meaning light and voltaic which refers to producing electricity. Therefore, the photovoltaic process is "producing electricity directly from sunlight" Photovoltaic is often referred to as PV. Pv systems are being installed by Texans who already have grid-supplied electricity but want to begin to live more independently or who are concerned about the environment. For some applications where small amounts of electricity are required like emergency call boxes, PV systems are often cost justified even when grid electricity is not very far away. When applications require larger amounts of electricity and are located away from existing power lines, photovoltaic systems can in many cases offer least expensive, most viable option.
In use today on street lights, gate openers and other low power tasks, photovoltaic are gaining popularity in Texas and around the world as their price declines and efficiency increases.
How it Works PV cells converts sunlight directly into electricity without creating any air or water pollution. PV cell are made of at least two layers of semiconductor material. One layer has a positive charge, the other negative. when light enters the cell, some of the photons from the light are absorbed by the semiconductor atoms, freeing electrons from the cells negative layer to flow through an external circuit and back into the positive layer. This flow of electrons produces electric current. To increase their utility, dozens of individual PV cells are interconnected together in a sealed, weatherproof package called a module. When two modules are wired together in series, their voltage is doubled while the current stays constant. When two modules are wired in parallel, their current is doubled while the voltage stays voltage and current, modules are wired in series and parallel into what is called a PV array. The flexibility of the modular PV system allows designers to create solar power systems that can meet a wide variety of electrical needs , no matter how large or small.
The Grid On or OFF Some homeowners in Texas are turning to PV as a clean and reliable energy source even though it is often more expensive than power
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available from their electricity utility. These homeowners can supplement their energy needs with electricity from their local utility when their PV system is not supplying enough energy (at night time and on cloudy days) and can export excess electricity back to their local utility when their PV system is generating more energy than is needed. Fore locations that are "off the grid" meaning they are far from or do not use existing power lines. PV system can be used to power water pumps, electric fences or even an entire household. While PV systems may require a substantial investment, they can be cheaper than paying the costs associated with extending the electric utility grid. a consumer in Texas may be asked to pay anywhere from $5,000 to $30,000 per mile to extend power lines.
The Right Equipment for the job A grid connected PV system will require a utility Dc to AC inverter. This device will convert the direct current (DC) electricity produced by the PV array into alternating current (AC) electricity typically required for loads such as radios, television and refrigerators. Utility interactive inverters also have built in safety features required by electric utilities nationwide. Prepared By zone4info.com Team Source: Renewable Energy (The infinite power of Texas)
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Zone4info - Transformers, Harmonic Currents and Phase Shifting
Transformers, Harmonic Currents and Phase Shifting Posted by Ackerley Acton September 19
Harmonic currents are omnipresent in electrical distribution systems and can cause a variety of problems. It is therefore important to understand which solutions are available to us. In this article, we will review various ideas that will be useful for solving problems related to power quality. Phase Shifting and Harmonics The best way to eliminate harmonics is to use a technique known as “phase shifting.” The concept of phase shifting involves separating the electrical supply intoseveral outputs; each output being phase shifted with the other outputs with an appropriate angle for the harmonics to be eliminated. The idea is to displace the harmonic currents in order to bring them to a 180° phaseshift so that they cancel each other out. Hence, an angular displacement of −60° is required between two three-phase outputs to cancel the 3rd harmonic currents −30° is required between two three-phase outputs to cancel the 5th and 7th harmonic currents −15° is required between two three-phase outputs to cancel the 11th and 13th harmonic currents For instance, in the case of two variable-speed drives of similar ratings, installing a Delta Wye transformer (30° phase shift with respect to the primary) on one drive and a delta-delta transformer (0° phase shift with respect to the primary) on the other drive gives an angular displacement of 30° between the two outputs. On the common primary supply of both transformers, phase shifting between the systems will cancel the 5th and 7th harmonic currents The above approach, i.e. phase-shifting non-linear loads, can be used to reduce the effects of certain harmonics. Current Harmonics, Voltage Distortion and Transformers The mathematical equation V = RI shows that any current flowing within a resistance (impedance) generates voltage at the terminals. This equation also applies to harmonic currents flowing through the electrical system. The higher the harmonic current levels, the greater the resulting harmonic voltages, thus creating distortion in the electrical system voltage. As transformers also have impedance, voltage distortion appears at the transformer’s secondary terminals when harmonic currents flow through it.
Therefore, to reduce voltage distortion two factors can be modified: the level of harmonic currents and transformer impedance. Phase-Shifting Transformers Designed for Non-Linear Loads The level of harmonic currents may be reduced using phase-shifting transformers. Low impedance plays a crucial role in reducing voltage distortion. New low-impedance phase-shifting transformers allow the treatment of harmonic currents while providing a path of low impedance. Moreover, these transformers have been designed to withstand the additional overheating caused by harmonic currents. The quality and reliability ofthe electrical system can be improved considerably through the use of a single piece of equipment. Prepared By: Zone4info.com Source: Harmmond Power Solutions Inc
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Zone4info - Permissive overreaching transfer trip
Permissive overreaching transfer trip Posted by Electrical Engineering Design September 16
A more common, and less expensive, solution to increase the security of the DTT is to provide an overreaching fault detector in a permissive overreaching transfer trip (POTT) scheme. This is some-what similar to the directional comparison blocking scheme in which the directional overreaching relay serves as both the fault detector (similar to the nondirectional impedance relay in the blocking scheme) and as a permissive interlock to prevent inadvertent trips due to noise. The received signal provides the tripping function. A trip signal, instead of a blocking signal, is used and each termi-nal is tuned to a different frequency and, therefore, can only respond to the remote transmitter’s signal. The settings can be ‘tighter’ than in the directional comparison blocking scheme, i.e. the overreaching relay only has to see beyond the next bus section; there is no need to coordinate with a blocking relay of an adjacent line. Referring to , directional overreaching relays 21-1o and 21-2o send tripping signals to the remote ends. Note that only an internal fault will cause both directional overreaching relays to operate; an external fault at either terminal will be seen by only one of the two directional overreaching relays. A trip, therefore, will be initiated if the local overreaching relay operates and a tripping signal is received from the remote terminal. Tripping is now dependent on both a
transmitted signal from the remote end, which will cause 85-1 G2 to drop out and 85-1 T2 to pick up, and the overreaching fault detector 21-1o picking up at the local terminal. Example 6.3 Consider the transmission line shown in Figure 6.15 protected by a POTT scheme using admittance-type relays at both ends for the overreaching function. Calculate the settings and draw the relay characteristics on anR–Xdiagram.
Example 6.4 Example 6.4 Consider the transmission line shown in Figure 6.17 with section AB protected by a permissive underreaching transfer trip (PUTT) scheme using admittance-type relays at both ends for the under-reaching and overreaching functions. Calculate the settings and draw the relay
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characteristics on anR–Xdiagram. At bus A,Ro equals 150% of Zline or 15.3 ,and Ru is 90%×10.0or9.2 . At bus B the same settings could be used, i.e.Ro=15.3 and Ru=9.2 .
Prepared By: Electrical Engineering Design (Electrical-ed.com)
Reference: Power System Protection.
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Zone4info - Tripping versus blocking
Tripping versus blocking Posted by Electrical Engineering Design September 16
The selection of a communication channel for protection is based upon a great many factors such as cost, reliability, the number of terminals and the distance between them, the number of channels required for all purposes, not only relaying, available frequencies and the prevailing practices of the power company. In addition to these fundamental considerations, either as another factor to be included or as a result of the selection already agreed upon, a decision must be made whether to operate in a blocking or a tripping mode. A blocking mode is one in which the presence of a transmitted signal prevents tripping of a circuit breaker, and a tripping mode is one in which the signal initiates tripping a circuit breaker. Thereare different relay schemes that accommodate one mode or the other. These will be discussed in detail. Basically, however, the criterion upon which the decision to use a block or trip signal is based on the relationship between the power line and the communication channel. The use of a blocking signal is preferred if the communication medium is an integral part of the protected line section, such as PLC. In this case, an internal fault may prevent or seriously attenuate the signal so that a trip signal would not be received. If a separate transmission medium such as microwave, fiber-optic cable or a pilot cable is used then the integrity of the power line during an internal fault will have no effect on the transmitted signal and a tripping scheme is a viable application. In many EHV systems, two primary protection schemes are used, in which case one may be a tripping system and the other may be a blocking system, which will then provide diversity Prepared By: Electrical Engineering Design (Electrical-ed.com)
Reference: Pilot protection of transmission lines.
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Zone4info - Transformer's Burden
Transformer's Burden Posted by Ackerley Acton September 13
The load of a current transformer is called the burden and can be expressed either as a VA load or as an impedance. In the former case the VA is taken to be at the CT nominal secondary current. For example, a 5 VA burden on a 1 A transformer would have an impedance of 5 ohms. 5VA / 1A = 5 V impedance = 5 V / 1 A = 5 Ohm or on a 5 A current transformer: 5 VA / 5 A = 1 V impedance: 1 V / 5 A = 0.2 ohm All burdens are connected in series and the increase in impedance increases the burden on the current transformer. A current transformer is unloaded if the secondary winding is short-circuited as under this condition the VA burden is zero because the voltage is zero. The errors of transformation depend on the angle of the burden as well as its impedance.
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Zone4info - Principle of the construction and operation of the electromechanical IDMTL relay
Principle of the construction and operation of the electromechanical IDMTL relay Posted by Electrical Engineering Design September 11
As the name implies, it is a relay monitoring the current, and has inverse characteristics with respect to the currents being monitored. This (electromechanical) relay is without doubt one of the most popular relays used on medium- and low-voltage systems for many years, and modern digital relays’ characteristics are still mainly based on the torque characteristic of this type of relay. Hence, it is worthwhile studying the operation of this relay in detail to understand the characteristics adopted in the digital relays
Typical mechanical relay
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The current I1from the line CTs, sets up a magnetic flux A and also induces a current I2 in the secondary winding which in turn sets up a flux in B. Fluxes A and B are out of phase thus producing a torque in the disk causing it to rotate. Now, speed is proportional to braking torque, and is proportional to driving torque. Therefore, speed is proportional to I². But, Speed = Distance / Time Hence, Speed = Distance / Time = 1 / (I)^2 This therefore gives an inverse characteristic
It can be seen that the operating time of an IDMTL relay is inversely proportional to a function of current, i.e. it has a long operating time at low multiples of setting current and a relatively short operating time at high multiples of setting current. The characteristic curve is defined by BS 142 and is shown in Figure 9.4. Two adjustments are possible on the relay, namely: 1. The current pick-up or plug setting: This adjusts the setting current by means of a plug bridge, which varies the effective turns on the upper electromagnet. 2. The time multiplier setting: This adjusts the operating time at a given multiple of setting current, by altering by means of the torsion head, the distance that the disk has to travel before contact is made. Prepared By: Electrical Engineering Design (Electrical-ed.com)
Reference: Power System Proctive Relay.
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Zone4info - System and equipment grounding functions
System and equipment grounding functions Posted by Electrical Engineering Design September 10
System grounding pertains to the manner in which a circuit conductor of a system is inten-tionally connected to earth, or to some conducting body that is effectively connected to earth or serves in place of earth. The following types of system grounding are discussed in this topic 1. Solidly grounded.A grounding electrode conductor connects a terminal of the system to the grounding electrode (s) and no impedance is intentionally inserted into the con-nection. 2. Resistance grounded.A grounding resistor is inserted into the connection between a terminal of the system and the grounding electrode(s). 3. Ungrounded.None of the circuit conductors of the system is intentionally grounded. Equipment grounding is the process of bonding together, with equipment-grounding conduc-tors, all conductive enclosures for conductors and equipment within each circuit. These equipment-grounding conductors are required to run with or enclose the circuit conductors, and they provide a permanent, low-impedance conductive path for groundfault current. In solidly grounded systems, the equipment-grounding conductors are bonded to the grounded circuit conductor and to the system-grounding conductor(s) per the National Electrical Code (NEC) (NFPA 70-1996), Section 250-50(a), at specific points, as shown in figures 7-1 and 7-2. System grounding functions Systems and circuit conductors are grounded to overvoltages due to lightning, line surges, or unintentional contact with higher voltage lines, and to stabilize the voltage-to-ground during normal operation. Systems and circuit conductors are solidly grounded to facilitate overcur-rent device operation in case of ground faults, and to stabilize voltage-to-ground during fault conditions
Grounding electrodes and the grounding electrode conductors that connect the electrodes to the system-grounding conductor are not intended to conduct ground-fault currents that are due to ground faults in equipment, raceways, or other conductor enclosures. In solidly grounded systems, the ground-fault current flows through the equipment-grounding conduc-tors from a ground fault anywhere in the system to the bonding jumper between the equip-ment-grounding conductors and the system-grounding conductor, as shown in figures 7-2 and 7-3. In solidly grounded service-supplied systems, the ground-fault current return path is com-pleted through the bonding jumper in the service equipment and the grounded service con-ductor to the supply transformer. Although the term “system grounding” is used in figures 7-2 and 7-3 for neutral grounding of utility transformers as well as for neutral grounding of service equipment, there is no inten-tion to imply that these two forms of grounding are functionally equivalent.
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Equipment grounding functions Equipment grounding systems, consisting of interconnected networks of equipment-ground-ing conductors, perform the following basic functions
System and equipment grounding for solidly grounded, separately derived system
Supplemental equipment bonding for separately derived system 1. They limit the voltage to ground (shock voltage) on the exposed noncurrent-carrying metal parts of equipment, raceways, and other conductor enclosures in case of ground faults. 2. They safely conduct ground-fault currents of sufficient magnitude for fast operation of the circuit-protective devices. 3. They reduce electromagnetic interference (EMI), common-mode noise, and other electronic interference. In order to ensure the performance of the above basic functions, equipment-grounding con-ductors should 1. Be permanent and continuous; 2. Have ample capacity to safely conduct any ground-fault current likely to be imposed on them; 3. Have impedance sufficiently low to limit the voltage to ground to a safe magnitude and to facilitate the operation of the circuit-protective devices. a person contacting a conductive enclosure in which there is a ground fault will be protected from shock injury if the equipment-grounding conductors provide a shunt path of sufficiently low impedance to limit the current through the person's body to a safe magnitude. In solidly grounded systems, the ground-fault current actuates the circuit-protective devices to automatically de-energize a faulted circuit and remove any destructive heating, arcing, and shock hazard. The same network of equipment-grounding conductors should be provided for solidly grounded systems, high-resistance grounded systems, and ungrounded systems. Equipment-grounding conductors are required in resistance grounded and ungrounded systems to pro-vide shock protection and to present a low-impedance path for phase-to-phase fault currents in case the first ground fault is not located and cleared before another ground fault occurs on a different phase in the system. Supplemental equipment bonding Exposure to electrical shock can be reduced by additional supplemental equipment bonding between the conductive enclosures for conductors and equipment and adjacent conductive materials. The supplemental equipment bonding shown in figure 7-3 contributes to equalizing the potential between exposed noncurrent-carrying metal parts of the electric system and adja-cent grounded building steel when ground faults occur. The inductive reactance of the ground-fault circuit will normally prevent a significant amount of ground-fault current from flowing through the supplemental bonding connections. Ground-fault current will flow through the path that provides the lowest ground-fault circuit impedance. The ground-fault current path that minimizes the inductive reactance of the
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ground-fault circuit is through the equipment-grounding conductors that are required to run with or enclose the circuit conductors. Therefore, practically all of the ground-fault current will flow through the equipment-grounding conductors, and the ground-fault current through the supplemental bonding connections will be no more than required to equalize the potential at the bonding locations. Prepared By: Electrical Engineering Design (Electrical-ed.com)
Reference: Energy Management in Industrial and Commercial Facilities
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Zone4info - Overcurrent differential relays (Device 87)
Overcurrent differential relays (Device 87) Posted by Mark David September 7
An overcurrent differential relay operates on a fixed current differential and can be easily affected by CT errors. It is the least expensive form of differential relaying, but it has the least sensitive settings compared to other forms, especially for detecting low-level ground faults. Figure shows differential protection applied on one phase. (Three relays—one per phase—are required.) Both ends of the protection zone should be available for the installation of the CTs. Under normal conditions, the current flowing in each CT secondary winding is the same, and the differential current flowing through the relay operating winding is zero. For an internal fault in the zone, the CT currents are no longer the same, and the differential current flows through the relay operating circuit. When the current through the relay’s operating circuit exceeds its pickup setting, the relay provides an output to trip the circuit breakers.
Overcurrent relay used for differential protection, one phase shown Under normal operating conditions, circumstances may produce a differential current to flow through the operating winding of the relay. One example of this situation is CT performance. CTs do not always perform exactly in accordance with their ratios. This difference is caused by minor variations in manufacture, differences in secondary loadings, and differences in magnetic history. Where a prolonged dc component exists in the primary fault current, such \as invariably occurs close to generators, the CTs do not saturate equally, and a substantial relay operating current can be expected to flow. Hence, if overcurrent differential relays are used, they have to be set so that they do not operate on the maximum error current, which can flow in the relay during an external fault. Because of the sensitiveness of this circuit, the overcurrent relay pickup should be set high enough to allow for these minor variations. However, while increasing its security, the higher pickup settings reduce the sensitivity of this circuit. To address this problem without sacrificing sensitivity, the percentage differential relay is usually used. A high-speed, economical overcurrent differential relay can be applied to motor protection for phase-to-phase and phase-to-ground faults. Figure shows how one toroidal CT per phase measures the phase current and produces a differential current to the relay for a fault. Fault currents as low as 2 A may be detected, and this application should follow the manufacturer’s recommendations concerning the CTs and the relay
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Differential protection of a motor using donut CTs and overcurrent relays Prepared by: Zone4info.com Reference: IEEE_STD_242
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Zone4info - Capacitors in Electric Circuits
Capacitors in Electric Circuits Posted by Ackerley Acton September 3
Capacitors in Electric Circuits A capacitor can be charged by connecting the plates to the terminals of a battery, which are maintained at a potential difference VΔ called the terminal voltage. The connection results in sharing the charges between the terminals and the plates. For example, the plate that is connected to the (positive) negative terminal will acquire some (positive) negative charge. The sharing causes a momentary reduction of charges on the terminals, and a decrease in the terminal voltage. Chemical reactions are then triggered to transfer more charge from one terminal to the other to compensate for the loss of charge to the capacitor plates, and maintain the terminal voltage at its initial level. The battery could thus be thought of as a charge pump that brings a charge Qfrom one plate to the other.
Parallel Connection Suppose we have two capacitors C1 with charge Q1 and C2 with charge Q2 that are connected in parallel, as shown in Figure
The left plates of both capacitors C1 and C2 are connected to the positive terminal of the battery and have the same electric potential as the positive terminal. Similarly, both right plates are negatively charged and have the same potential as the negative terminal. Thus, the potential difference |DELTA| is the same across each capacitor. This gives
These two capacitors can be replaced by a single equivalent capacitor with a total charge QeqC supplied by the battery. However, since Q is shared by the two capacitors, we must have
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The equivalent capacitance is then seen to be given by
Thus, capacitors that are connected in parallel add. The generalization to any number of capacitors is
Series Connection Suppose two initially uncharged capacitors C1 and C2 are connected in series, as shown in Figure 5.3.3. A potential difference ||VΔ is then applied across both capacitors. The left plate of capacitor 1 is connected to the positive terminal of the battery and becomes positively charged with a charge +Q, while the right plate of capacitor 2 is connected to the negative terminal and becomes negatively charged with charge –Q as electrons flow in. What about the inner plates? They were initially uncharged; now the outside plates each attract an equal and opposite charge. So the right plate of capacitor 1 will acquire a charge –Q and the left plate of capacitor +Q.
Capacitors in series and an equivalent capacitor The potential differences across capacitorsC1 and C2 are
respectively. From Figure 5.3.3, we see that the total potential difference is simply the sum of the two individual potential differences:
In fact, the total potential difference across any number of capacitors in series connection is equal to the sum of potential differences across the individual capacitors. These two capacitors can be replaced by a single equivalent capacitor Ceq=Q /|V|. Using the fact that the potentials add in series,
and so the equivalent capacitance for two capacitors in series becomes
The generalization to any number of capacitors connected in series is
Prepared By: zone4info.com Team
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Source: Capacitance and Dielectrics Book Â
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Zone4info - THERMAL POWER
THERMAL POWER Posted by Ackerley Acton September 3
THERMAL POWER Thermal generating stations burn COAL, OIL or NATURAL GAS to generate electricity. In the case of a coal-fired generating station, the coal is stored in large coal piles just outside the station. From there, the coal is brought into the station on a conveyor belt where it is fed into large pulverizers that crush the coal into a fine powder. Large fans blow the coal powder into a giant furnace where it is burned giving off vast amounts of heat. The temperature in the furnace can reach over 3,000oC. The furnace is surrounded by tubes filled with water. The immense heat from the burning coal turns the water in the tubes into steam. The steam is then transferred under pressure at high speed through large pipes to a turbine where it pushes the turbine blades causing them to spin. From there, the process is the same as in a nuclear or a hydroelectric generating station; the turbine spins the generator producing electricity. The steam is condensed back to water using cooling water, usually from a nearby lake or river. It is then pumped back into the water tubes surrounding the furnace to continue the process.
THERMAL GENERATING STATION
Natural gas power plants such as the Portlands Energy Centre located in Toronto help to meet Ontario’s peak demand for electricity. Thermal plants use fossil fuels or could use new fuels like biomass. Ontario will phase out the use of coal by the end of 2014. Thermal plants play an important role because, unlike a nuclear station, they are able to quickly adjust to changes in electricity demand. Their output can be easily increased to help meet periods of peak demand and provide backup for intermittent sources like wind and solar. Burning fossil fuels to generate electricity creates a number of byproducts that impact the environment. These include gases like SULFUR DIOXIDE (SO2) and NITROGEN OXIDES (NOX) which contribute to smog and acid rain. Some of Ontario’s coal-fired generation stations use special technologies that can reduce or almost eliminate these pollutants. Another gas that is released when burning fossil fuels is CARBON DIOXIDE (CO2), which is a GREENHOUSE GAS. Greenhouse gases trap heat in the earth’s atm osphere and can cause temperatures on the earth’s surface to rise. This effect is known as global warming.
THE GLOBAL CARBON CYCLE
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The carbon cycle is the process through which carbon is cycled through the air, ground, plants, animals, and fossil fuels. Carbon is stored in fossil fuels, over millions of years. When these fuels are burned, the carbon dioxide stored in them is released back into the air. Prepared By: zone4info.com Team Source: www.ieso.ca
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Zone4info - Nuclear power
Nuclear power Posted by Johan column August 27
Nuclear power Nuclear power plants use URANIUM to generate heat and boil water into steam. Uranium has the largest atoms of the 92 naturally occurring elements on earth, making uranium atoms more likely than other atoms to split. When subatomic particles called NEUTRONS come in contact with uranium atoms, the atoms split releasing heat energy. This occurs all the time in nature, but at a very slow rate. Nuclear reactors are able to greatly speed up this process by slowing down the neutrons and increasing the likelihood that they will hit and split the uranium atoms. When uranium atoms split they also release more neutrons which can then go on and split additional atoms ensuring a chain reaction of atom splitting. This is called NUCLEAR FISSION.
One of these half-metre nuclear fuel bundles can provide enough electricity to power 100 homes for a year. At the heart of every nuclear reactor are FUEL PELLETS no bigger than the tip of your finger. Despite their small size, these fuel pellets hold the potential to produce tremendous amounts of energy.
A single nuclear fuel pellet like the one shown above can power an average home for 6 weeks. At the heart of every nuclear reactor are FUEL PELLETS no bigger than the tip of your finger. Despite their small size, these fuel pellets hold the potential to produce tremendous amounts of energy. Ontario’s nuclear reactors use fuel pellets that are made from naturally occurring uranium that is mined in Canada. The pellets are inserted into tubes about half-a-metre in length made from a zirconium alloy, a special type of metal that has a high resistance to corrosion. The tubes are welded shut and several are assembled together into what is called a FUEL BUNDLE. One of these half-metre fuel bundles can provide enough electricity to power 100 homes for a year.
Thousands of fuel bundles are inserted into the core of a nuclear reactor where the uranium atoms split giving off vast amounts of heat. The heat is used to boil water to create steam, which then spins a turbine and generator producing electricity.
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Ontarioâ&#x20AC;&#x2122;s Darlington Nuclear Station is one of the most efficient nuclear stations in the world and is capable of powering 17% of the entire province. Nuclear power stations are able to produce tremendous amounts of electricity from a very small amount of fuel. A single 2.5 centimetre nuclear fuel pellet can produce the same amount of energy as 807 kilograms of coal, 677 litres of oil, or 476 cubic metres of natural gas. As well, because nuclear power plants do not burn any fuels, they produce virtually no smog or greenhouse gas emissions. They do however produce nuclear waste which needs to be handled and stored very carefully. Â
NUCLEAR GENERATING STATION
Diagram of a nuclear generating station.
MANAGING NUCLEAR WASTE When uranium atoms split they form smaller atoms, called FISSION PRODUCTS. These fission products are highly radioactive. As a result, the fuel bundles that hold the uranium need to be isolated from the environment for an extended period of time once they are removed from a reactor. Fission products are so unstable they fall apart or disintegrate. When this happens, tiny fragments of the fission products are emitted in all directions. Atoms that spontaneously disintegrate in this manner are said to be radioactive.
A worker at the Pickering Nuclear Station looks over the used fuel bundles in the water-filled bay. The fuel bundles will remain in the water for about 10 years. When they can no longer generate heat efficiently, used fuel bundles are removed from the reactor and placed in WATER-FILLED BAYS to cool down. These water-filled bays are located on the same site as the reactors and are built using reinforced concrete, lined to prevent leaks and designed to withstand earthquakes. The water in the bays helps cool the fuel bundles as well as provide shielding from radiation. The fuel bundles will remain in the bays for approximately 10 years after which time they will have cooled and the radiation they emit will have decreased significantly. The fuel bundles are then removed from the bay and placed in what are called DRY STORAGE CONTAINERS. These containers are made of
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concrete and steel and provide shielding from radiation. The containers are welded shut and stored in highly secure warehouses located on the same site as the nuclear generating station.
After being removed from the water-filled bays, the used fuel is placed in storage containers like the ones shown here. The containers are stored on the site of the nuclear station in highly secure warehouses where they are constantly monitored. Canada’s long-term plan for managing used nuclear fuel is to have a central, contained isolation facility in a deep rock formation. In the interim, scientists around the world are looking for new and innovative solutions to manage nuclear waste over time. Prepared By: zone4info.com Source:www.ieso.ca
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Zone4info - Understanding Power Demand
Understanding Power Demand Posted by Zeshan Rajput August 26
Understanding Power Demand Unlike other commodities, electricity needs to be consumed as it is generated. There is currently no economical way to store large quantities of electricity for later use. The supply and demand for electricity must be kept in constant balance. As demand increases, the supply must increase proportionately. Electricity is usually measured in kilowatts and megawatts. One megawatt is equal to 1,000 kilowatts. 1 kilowatt could power ten 100-watt light bulbs or fifty 20-watt compact fluorescent lights. To power the light bulbs for an hour you would need 1 kilowatt hour of electricity. A kilowatt hour is the amount of electricity consumed or generated over a 1 hour period. An average house consumes 1,000 kilowatt hours of electricity a month. Our society has a constant demand for electricity. Even when you are asleep, think of all the things in your home that continue using electricity like air conditioning, outdoor lighting, digital clocks, and all the gadgets that need to be recharged for the next day.
Source: www.ieso.ca Prepared By: Zone4info.com Team
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Zone4info - Generating Power
Generating Power Posted by Zeshan Rajput August 26
Generating Power Most power plants, whether they are nuclear, hydroelectric, fossil-fuelled or wind, do essentially the same job, transforming kinetic energy, the energy of motion, into a flow of electrons, or electricity. At a power plant, a GENERATOR is used to make electricity. Inside a generator, a magnet called a ROTOR spins inside coils of copper wire called a STATOR. This pulls the electrons away from their atoms, and a flow of electrons is created in the copper wires. Those electrons can then be sent along power lines to wherever electricity is needed. In a generator, magnets pull electrons away from atoms in copper wire creating a flow of electrons in the copper wire. This flow of electrons is what we know as electricity. Giant wheels called TURBINES are used to spin the magnets inside the generator. It takes a lot of energy to spin the turbine and different kinds of power plants get that energy from different sources. In a hydroelectric station, falling water is used to spin the turbine. In nuclear stations and in thermal generating stations powered by fossil fuels, steam is used. A wind turbine uses the force of moving air.
Prepared By: Zone4info.com Team Source: www.ieso.ca
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Zone4info - Earthing Transformers
Earthing Transformers Posted by Zeshan Rajput August 25
Earthing Transformers In areas where earth point is not available, a neutral point is created using an earthing transformer. Earthing transformer, having the zig-zag (interstar) winding is used to achieve the required zero phase impendence stage which provides the possibility of neutral earthing condition. In addition an auxiliary windings can also be provided to meet the requirement of an auxiliary power supply. Earthing transformers are usually oil immersed and may be installed outdoor. As for connection, the earthing can be connected directly, through an arc-suppression reactor or through a neutral earthing reactor or resistor. In cases where a separate reactor is connected between the transformer neutral and earth, the reactor and the transformer can be incorporated into the same tank. Earthing Transformer’s system ranges from 11kV to 33kV. Standard accessories and fittings are as follows: Silica Gel Breather Conservator Bucholz Relay Oil Temperature Indicator Uninhibited Oil LV (415kV) Switchfuse Pressure Relief Device Drain Valve Gate Valve Prepared By: zone4info.com Source: http://www.ewt.com.my/
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Zone4info - Primary and Backup Protection
Primary and Backup Protection Posted by Johan column August 25
Primary and Backup Protection The protection provided by the protective relaying equipment can be categorised into two types as: 1- Primary protection 2- Backup protection The primary protection is the first line of defence and is responsible to protect all the power system elements from all the types of faults. The backup protection comesinto play only when the primary protection fails The backup protection is provided as the main protection can fail due to many reasons like, 1- Failure in circuit breaker 2- Failure in protective relay 3- Failure in tripping circuit 4- Failure in d.c tripping voltage 5- Loss of voltage or current supply to the relay Thus if the backup protection is absent and the main protection fails then there is a possibility of server damage to the system When the primary protection is made inoperative for the maintenance purpose, the backup protection acts like a main protection. The arrangement of backup protective scheme should be such that the failure in main protection should not cause the failure in back up protection as well. This is satisfied if back up relaying and primary relaying do not have anything common. Hence generally backup protection is located at different stations from the primary protection. From the cost and economy point of view, the back up protection is employed only for the protection against short circuit and not for any other abnormal conditions Concept of Back Relaying Consider the back relaying employed for the transmission line section EF as shown in the fig
The relays C,D,G and H are primary relays while A,B,I and J are the backup relays. Normally backup relays are tripped if primary relay fails. so if the primary relay E fails to trip, then backup relays A and B get tripped. The backup relays and associated backup relaying equipments are physically apart from the faulty equipment. The backup relays A and B provide backup protection for fault at station K. Also the backup relays at A and F provide the backup protection for the faults in line DB. The backup relaying often provides primary protection when the primary relays are out of service for repairs. It is obvious that when the backup relay operates, the larger part of the system is disconnected. The important requirement of backup relaying is that it must operate with sufficient time delay so that the primary relaying is given a chance to operate. When fault occurs, both the type of relays starts relaying operation but primary is expected to trip first and backup will then reset without having had time to complete its relaying operation. When the given set of relays provides the backup protection for several adjacement system elements then the slowest primary
relaying of any those will determine the necessary time delay of the given backup relays. Methods of Backup Protection 1- Relay backup protection: In this scheme, a single breaker is used by both primary as well as backup protection but the two protective systems are different 2- Breaker backup Protection: In this method, separate breakers are provided for primary and backup protection. Both the types of breakers are at the same station 3- Remote Backup Protection: In this method, separate breaker are provided for primary and backup protection. The two types of breaker are at the different stations and are completely isolated and independent of each other. 4- Centrally Co-ordinated Backup Protection: In this method, primary protection is at various stations. There is a central control room and backup protection for all the stations is at central control room. central control continuously inspects the load flow and frequency in the system. If any element of any part of the system fails, load flow gets affected which is sensed by the control room. The control source consists of a digital computer which decides the proper switching action. The method is also called centrally controlled backup ptotection. Prepared By: Zone4info.com Team Source: Power System Protection Book
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Zone4info - Neutral grounding of power systems
Neutral grounding of power systems Posted by Johan column August 24
Neutrals of power transformers and generators can be grounded in a variety of ways, depending upon the needs of the affected portion of the power system. As grounding practices affect fault current levels, they have a direct bearing upon relay system designs. In this section, we will examine the types of grounding system in use in modern power systems and the reasons for each of the grounding choices. Influence of grounding practices on relay system design will be considered at appropriate places throughout the remainder of this topic. It is obvious that there is no ground fault current in a truly ungrounded system. This is the main reason for operating the power system ungrounded. As the vast majority of faults on a power system are ground faults, service interruptions due to faults on an ungrounded system are greatly reduced. However, as the number of transmission lines connected to the power system grows, the capacitive coupling of the feeder conductors with ground provides a path to ground, and a ground fault on such a system produces a capacitive fault current. This is illustrated in Figure (a). The coupling capacitors to ground C0 provide the return path for the fault current. The interphase capacitors 1/3C1 play no role in this fault. When the size of the capacitance becomes sufficiently large, the capacitive ground fault current becomes self-sustaining, and does not clear by itself. It then becomes
Neutral grounding impedance. (a) System diagram. (b) Phasor diagram showing neutral shift on ground fault necessary to open the circuit breakers to clear the fault, and the relaying problem becomes one of detecting such low magnitudes of fault currents. In order to produce a sufficient fault current, a resistance is introduced between the neutral and the ground – inside the box shown by a dotted line in Figure (a). One of the design considerations in selecting the grounding resistance is the thermal capacity of the resistance to handle a sustained ground fault. Ungrounded systems produce good service continuity, but are subjected to high overvoltages on the unfaulted phases when a ground fault occurs. It is clear from the phasor diagram of Figure (b) that when a √ ground fault occurs on phase a, the steady-state voltages of phases b and c become 3 times their normal value. Transient overvoltages become correspondingly higher. This places additional stress on the insulation of all connected equipment. As the insulation level of lower voltage systems is primarily influenced by lightninginduced phenomena, it is possible to accept the fault-induced overvoltages as they are lower than the lightning-induced overvoltages. However, as the system voltages increase to higher than about 100 kV, the fault-induced overvoltages begin to assume a critical role in insulation design, especially of power transformers. At high voltages, it is therefore common to use solidly grounded neutrals (more precisely ‘effectively grounded’). Such systems have high ground fault currents, and each ground fault must be cleared by circuit breakers. As high-voltage systems are generally heavily interconnected, with several alternative paths to load centers, operation of circuit breakers for ground faults does not lead to a reduced service continuity. In certain heavily meshed systems, particularly at 69 kV and 138 kV, the ground fault current could become excessive because of very low zero sequence impedance at some buses. If ground fault current is beyond the capability of the circuit breakers, it becomes necessary to insert an inductance in the neutral in order to limit the ground fault current to a safe value. As the network Th´evenin impedance is primarily inductive, a neutral inductance is much more effective (than resistance) in reducing the fault current. Also, there is no significant power loss in the neutral reactor during ground faults. In several lower voltage networks, a very effective alternative to ungrounded operation can be found if the capacitive fault current causes ground faults to be self-sustaining. This is the use of a Petersen coil, also known as the ground fault neutralizer (GFN). Consider the symmetrical component representation of a ground fault on a power system, which is grounded through a grounding reactance of Xn (Figure ). If 3Xn is made equal to Xc0 (the zero sequence capacitive reactance of the connected network), the parallel resonant circuit formed by these two elements creates an open circuit in the fault path, and the ground fault current is once again zero. No circuit breaker operation is necessary upon the occurrence of such a fault, and service reliability Prepared By: Zone4info.com Reference: Electrical Grounding System Handookg
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Zone4info - What is relaying?
What is relaying?
Posted by Zone 4info August 24
In order to understand the function of protective relaying systems, one must be familiar with the nature and the modes of operation of an electric power system. Electric energy is one of the fundamental resources of modern industrial society. Electric power is available to the user instantly, at the correct voltage and frequency, and exactly in the amount that is needed. This remarkable performance is achieved through careful planning, design, installation and operation of a very complex network of generators, transformers, and transmission and distribution lines. To the user of electricity, the power system appears to be in a steady state: imperturbable, constant and infinite in capacity. Yet, the power system is subject to constant disturbances created by random load changes, by faults created by natural causes and sometimes as a result of equipment or operator failure. In spite of these constant perturbations, the power system maintains its quasisteady state because of two basic factors: the large size of the power system in relation to the size of individual loads or generators, and correct and quick remedial action taken by the protective relaying equipment. Relaying is the branch of electric power engineering concerned with the principles of design and operation of equipment (called ‘relays’ or ‘protective relays’) that detects abnormal power system conditions, and initiates corrective action as quickly as possible in order to return the power system to its normal state. The quickness of response is an essential element of protective relaying systems – response times of the order of a few milliseconds are often required. Consequently, human intervention in the protection system operation is not possible. The response must be automatic, quick and should cause a minimum amount of disruption to the power system. As the principles of protective relaying are developed in this book, the reader will perceive that the entire subject is governed by these general requirements: correct diagnosis of trouble, quickness of response and minimum disturbance to the power system. To accomplish these goals, we must examine all possible types of fault or abnormal conditions which may occur in the power system. We must analyze the required response to each of these events, and design protective equipment which will provide such a response. We must further examine the possibility that protective relaying equipment itself may fail to operate correctly, and provide for a backup protective function. It should be clear that extensive and sophisticated equipment is needed to accomplish these tasks.
Prepared By: zone4info.com Source: Power System Relaying
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Zone4info - . Losses in Transformers
. Losses in Transformers Posted by Zone 4info August 15
The losses in a transformer are as under. 1. 2. 3. 4. 5. 6. structure.
Dielectric Loss Hysteresis Losses in the Core Eddy current losses in the Core Resistive Losses in the winding conductors Increased resistive losses due to Eddy Current Losses in conductors. For oil immersed transformers, extra eddy current losses in the tank
Basic description of the factors affecting these losses is given below. Dielectric Losses
This loss occurs due to electrostatic stress reversals in the insulation. It is roughly proportional to developed high voltage and the type and thickness of insulation. It varies with frequency. It is negligibly small and is roughly constant. (Generally ignored in medium voltage transformers while computing efficiency). Hysteresis Loss
A sizeable contribution to no-load losses comes from hysteresis losses. Hysteresis losses originate from the molecular magnetic domains in the core laminations, resisting being magnetized and demagnetized by the alternating magnetic field. Each time the magnetising force produced by the primary of a transformer changes because of the applied ac voltage, the domains realign them in the direction of the force. The energy to accomplish this realignment of the magnetic domains comes from the input power and is not transferred to the secondary winding. It is therefore a loss. Because various types of core materials have different magnetizing abilities, the selection of core material is an important factor in reducing core losses. Hysteresis is a part of core loss. This depends upon the area of the magnetising B-H loop and frequency. Refer Fig 2.4 for a typical BH Loop.
Energy input and retrieval while increasing and decreasing current. Loss per half cycle equals half of the area of Hysteresis Loop. The B-H loop area depends upon the type of core material and maximum flux density. It is thus dependent upon the maximum limits of flux excursions i.e. Bmax, the type of material and frequency. Typically, this accounts for 50% of the constant core losses for CRGO (Cold Rolled Grain Oriented) sheet steel with normal design practice.
Eddy Current Losses in the Core
The alternating flux induces an EMF in the bulk of the core proportional to flux density and frequency. The resulting circulating current depends inversely upon the resistivity of the material and directly upon the thickness of the core. The losses per unit mass of core material, thus vary with square of the flux density, frequency and thickness of the core laminations. By using a laminated core, (thin sheets of silicon steel instead of a solid core) the path of the eddy current is broken up without increasing the reluctance of the magnetic circuit. Refer fig 2.5 below for a comparison of solid iron core and a laminated iron core. Fig. 2.5B shows a solid core, which is split up by laminations of thickness â&#x20AC;&#x2DC;d1â&#x20AC;&#x2122; and depth d2 as shown in C. This is shown pictorially in 2.5 A.
Corelaminationtoreduceeddycurrentlosses
Where Ke Bm strips.
= the eddy current constant f = Frequency in Hertz. = Maximum flux density in Tesla t = Thickness of lamination
For reducing eddy losses, higher resistivity core material and thinner (Typical thickness of laminations is 0.35 mm) lamination of core are employed. This loss decreases very slightly with increase in temperature. This variation is very small and is neglected for all practical purposes. Eddy losses contribute to about 50% of the core losses. Prepared By: zone4info.com Source: IndianRenewableEnergyDevelopmentAgency,
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Zone4info - Parallel operation of transformers
Parallel operation of transformers Posted by Zone 4info August 15
Paralleloperationoftransformers
The parallel operation of transformers is common in any industry. This mode of operation is frequently required. When operating two or more transformers in parallel, their satisfactory performance requires that they have: 1. 2. 3. 4.
The same voltage-ratio The same per-unit (or percentage) impedance The same polarity The same phase-sequence and zero relative phase-displacement
Out of these conditions 3 and 4 are absolutely essential and condition 1 must be satisfied to a close degree. There is more latitude with condition 2, but the more nearly it is true, the better will be the load-division between the several transformers. Voltage Ratio: An equal voltage-ratio is necessary to avoid no-load circulating current, other wise it will lead to unnecessary losses. The impedance of transformers is small, so that a small percentage voltage difference may be sufficient to circulate a considerable current and cause additional I2R loss. When the secondaries are loaded, the circulating current will tend to produce unequal loading conditions and it may be impossible to take the combined full-load output from the parallel-connected group without one of the transformers becoming excessive hot. Impedance: The impedances of two transformers may differ in magnitude and in quality (i.e. ratio of resistance to reactance) and it is necessary to distinguish between per-unit and numerical impedance. Consider two transformers of ratings in the ratio 2:1. To carry double the current, the former must have half the impedance of the latter for the same regulation. The regulation must, however, be the same for parallel operation, this condition being enforced by the parallel connection. Hence the currents carried by two transformers are proportional to their ratings, if their numerical or ohmic impedances are inversely proportional to those ratings, and their per-unit impedances are identical. A difference in quality of the per-unit impedance results in a divergence of phase angle of the two currents, so that one transformer will be working with a higher, and the other with a lower, power factor than that of the combined output. Polarity: This can be either right or wrong. If wrong it results in a dead short circuit.
Phase-Sequence: This condition is associated only with polyphase transformers. Two transformers giving secondary voltages with a phase-displacement cannot be used for transformers intended for parallel-operation. The phase sequence or the order, in which the phases reach their maximum positive voltages, must be identical for two paralleling transformers; otherwise during the cycle each pair of phases will be shortcircuited. The two power transformers shall be paralleled only for a short duration, because they may be risking a higher fault level during this short period. The system impedance reduces when the two or more transformers are paralleled and hence increases the fault level of the system. Prepared By: zone4info.com
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Zone4info - How to calculate daily energy, capacity of plant, utilization factor of power plant
How to calculate daily energy, capacity of plant, utilization factor of power plant Posted by Zone 4info August 13
Peak demand of a genrating stations is 90 MW and load factor is 0.6. The plant capacity factor and plant use factor are 0.5 and 0.8 respectively. Determine (a) Daily energy produced (b) Installed capacity of plant (c) Reserve capacity of plant (d) Utilization factor Solution: (a) Maximum demand = 90 MW Load factor = 0.6 Average demand = (maximu demand ) x (load factor) Average demand = 90 x 0.6 = 54 MW Daily energy produced = Average demand x 24 = 54 x 24 = 1296 MWhr (b) Plant factor = Actual energy produced / Maximum plant rating x T Plant factor = 0.50 Actual energy produced = 1296 MWhr Maximum plant rating = (1296) / (0.50 x 24) = 108 Mw Installed Capacity = 108 MW
(C) Utilization factor is, UF = (Maximum demand of the system) / (Rated system Capacity) UF = 90 / 108 = 0.833 Prepared By: zone4info.com
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Zone4info - Disadvantages of low power factor
Disadvantages of low power factor Posted by Zone 4info August 13
Disadvantages of low power factor For a three phase balanced system, if load is P, terminal voltage is V and power factor is cos0 then load current is given by I = P / (1.732*Cos0 ) If the P and V are constant, the load current I is inversely proportional to the power factor, if cos0 is low, I is large. The poor power factor of the system has following disadvantages: 1- Rating of generators and transformers are inversely proportional to the power factor. Thus, generators and transformers are required to deliver same load (real power) at low power factor. Hence, system kVA or MVA supply will increase 2- At low power factor, the transmission lines, feeders or cable have to carry more current for the same power to be transmitted. Thus, conductor size will increase, if current density in feeder and cables to deliver the same load but at low power factor. 3- Power loss is proportional to the square of the current and hence inversely proportional to the square of the power factor. More power losses incur at low power factor and hence poor efficiency 4- Low lagging power factor results in large voltage drop which results in poor voltage regulation. Hence, additional regulating equipment is required to keep the voltage drop withine permissible limits Electric utitlies insist the industrial consumers to maintain a power factor 0.8 or above. The power tariffs are devised to penalize the consumer with low lagging power factor and force them to install power factor correction devices for example shunt capacitors Various Causes of low power factor 1- Most of the induction motors operate at lagging power factor. The power factor of these motor falls with the decrease of load
2- Occurrence of increased supply mains voltage during low load periods, the maganetizing current of inductive reactances increase and power factor of the electrical plant as a whole comes down 3- Very low lagging power factor of agriculure motor pump-set. 4- Arc lamps, electric discharge lamps and some other electric equipments operate at alow power factor 5- Arc and induction furnaces operate on very low lagging power factor Reference: Electrical Power System Book Prepared By: zone4info.com
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Zone4info - AC Motor Construction
AC Motor Construction
Posted by Johan column August 12
AC Motor Construction Three-phase AC induction motors are commonly used in industrial applications. This type of motor has three main parts, rotor, stator, and enclosure. The stator and rotor do the work, and the enclosure protects the stator and rotor.
Stator Core
The stator is the stationary part of the motor's electromagnetic circuit. The stator core is made up of many thin metal sheets, called laminations. Laminations are used to reduce energy losses that would result if a solid core were used.
Stator Windings Stator laminations are stacked together forming a hollow cylinder. Coils of insulated wire are inserted into slots of the stator core. When the assembled motor is in operation, the stator windings are connected directly to the power source. Each grouping of coils, together with the steel core it surrounds, becomes an electromagnet when current is applied. Electromagnetism is the basic principle behind motor operation.
Rotor Construction The rotor is the rotating part of the motor's electromagnetic circuit. The most common type of rotor used in a three-phase induction motor is a squirrel cage rotor. The squirrel cage rotor is so called because its construction is reminiscent of the rotating exercise wheels found in some pet cages. A squirrel cage rotor core is made by stacking thin steel laminations to form a cylinder.
Rotor Construction Rather than using coils of wire as conductors, conductor bars are die cast into the slots evenly spaced around the cylinder. Most squirrel cage rotors are made by die casting aluminum to form the conductor bars. Siemens also makes motors with die cast copper rotor conductors. These motors exceed NEMA Premium efficiency standards. After die casting, rotor conductor bars are mechanically and electrically connected with end rings. The rotor is then pressed onto a steel shaft to form a rotor assembly.
Enclosure
The enclosure consists of a frame (or yoke) and two end brackets (or bearing housings). The stator is mounted inside the frame. The rotor fits inside the stator with a slight air gap separating it from the stator. There is no direct physical connection between the rotor and the stator. The enclosure protects the internal parts of the motor from water and other environmental elements. The degree of protection depends upon the type of enclosure. Enclosure types are discussed later in this course.
Bearings and Fan
Bearings, mounted on the shaft, support the rotor and allow it to turn. Some motors, like the one shown in the accompanying illustration, use a fan, also mounted on the rotor shaft, to cool the motor when the shaft is rotating. Source: siemens.com Prepared By: zone4info.com
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Zone4info - System for measurement and prediction of energy savings in households
System for measurement and prediction of energy savings in households Posted by Johan column August 11
Generation, transmission and energy savings are very recently discussed topic. Already today this sector is affected by the expansion of renewable energy sources in the near future you can expect many more changes. While the most discussed topic in different "smart" technology, whether it is a local "smart home" or global "smart grid". The more involved in renewable energy storage and the lack of people will be more motivated to use energy when it is available. At present the prices of two different motivations tariff bands, the so-called high and low tariff electricity prices, which management is responsible for the MRC system. It is possible that this splitting into several tariff zones and there will be an even greater incentive to control the operation of appliances based on electricity production. In this case, it will be important to develop a system that will allow customers to monitor the current status of and manage their consumption, either manually adjusting their habits, or automatic control of appliances. Paper was also presented at the International Conference NZEE 2012 .
Introduction
The system for measuring, predicting and saving energy at home (the SMPS) is designed so that its use would require the least intervention into existing installations. Hand in hand with the launch and low cost system. The aim is to make the most of technologies that are already part of everyday life, thereby minimizing the scope of the system. SMPS is built modularly so that it can be continuously updated and expanded with additional functionality. Block diagram of the basic system can be seen in Figure 1 Communication of each block is solved using a wireless WiFi network. Such a network is already equipped with most households, which can be calculated with the
deployment of SMPS. The inspiration for this solution can be described as the use of Ethernet in the industry. Mass-used features have lower development costs and production, therefore, due to its low price and become attractive areas other than for which they were initially intended. Some of the blocks for which it is convenient position-can be combined into one larger unit equipped with a single WiFi interface. This price reduction is achieved and the energy performance of these blocks. Individual units have their own memory, so that might be able to work some time without access to the network. The collection and data access then the old server, based on the network. Where appropriate, this may be only the server software installed on the PC in the network. The disadvantage of this solution is that the computer must be switched on at least interval which corresponds to the period of filling of individual memory blocks. Another disadvantage is access to data from other devices only when the computer is in operation. Better solution is to use the data server using a low power computer. The market is a lot of equipment, capable and equipped to manage the database such as the Linux operating system and Ethernet interfaces. Data is normally stored on the SD card or flash memory.
Given that information on energy consumption could be helpful for criminal activity or otherwise abused, it is important that the data was sufficiently secured (not to mention the possibility of controlling some appliances). You can rely on basic security in Wi-Fi network, or have not improved data encryption. There is also the option to allow access only within the internal network, but unfortunately at the cost monitoring and control of comfort such as consumption or holiday job. SMPS is able to obtain data from the Internet. This capability adds a lot of interesting functionalities. For example, the system can update itself for energy prices, cost calculations, eventually. monitor the current rate for a given connection. But it can also respond to the weather forecast for the region and for example in advance to intervene in the regulation of the heating system depending on weather developments.
Module SM1
Baseline measurements of electric energy consumption of household electricity meter or object handles. Modern meters are already equipped with infrared interface, LED pulse output interface or even some of the fieldbus. One of the main requirements for SMPS but what is the easiest to install with the lowest cost. For this reason, this basic module is designed so that it can be connected to the meter for standard connection. This part of the leadership is already owned by customers, thus avoiding, in compliance with all regulations, the need for intervention by the distributor. Figure. 2 shows block connection module SM1. The working conductors are connected sensors needed for power measurements. At the same time from the power supply module. As part of this module is also the best location of the data and
web server that provides collection and delivery of the measured values.
Transferring data from this module, as in the whole system, implemented WiFi networks, but may be connected to the router and cable. In appropriate cases, the data could be operated even after the power line. Data measured SM1 module contains information about the entire electric power from the network. A detailed analysis of these data can identify the behavior of individual consumers, without the appliance directly measured separately.
SM2 module
We require the measurement of specific appliance, it is appropriate to use the module SM2. It is designed as a pass-through socket block.
Its installation is easy and requires no expertise. Block diagram of the module can be seen in Figure 3 This module can also be used to control appliances. Unfortunately, today there are many appliances equipped with digital controls and simple network connection is not enough to trigger the device. New modern devices are already equipped with an interface for management, for example, according to ČSN_EN_50523-1. We can only hope for an agreement among all manufacturers of standard, which will be used for communication with all appliances. Data between the module and the network again transferred WiFi networks, but it is possible to design transmission and power line. The module must be equipped with a memory that will be able to store measurement data used for in order not to lose, for example, communications network failure or server.
Additional modules
SMPS system is suitable for measuring samples of other energy and raw materials, such as gas or water. Water meters are equipped with optical odečítacím device, which may involve reflective sensor. The pulses from the sensor indicative of units
consumed media. Some measuring devices are fitted directly to the pulse output.
Conclusion
SMPS is an open system and can be complemented by additional modules. The range is limited only by the scope of Wifi networks. This network will certainly not be considered reliable, and therefore the system is not suitable for measurement or control in time-critical areas. Most modules are designed for measuring energy consumption, because it avoids the problem of obtaining power for measurement and data transmission. Some modules but not working with measurement of electricity, but for example the measurement of liquid media. In such cases it would be appropriate to use the power harvesting technology. For example, a small turbine would be capable of supplying sensor pulse meter. References: The Energy Regulatory Office, Annual Report on the operation of EC CR last updated 9th First 2012 Vesely, I.; Ĺ embera, J. (2011). Cogeneration unit in Smart Grid network. In Proceedings of the 5th Annual Conference of results of research, development and innovation for renewables. Corners of Desnou Ä&#x152;SN_EN_50523-1 Czech Republic, April, 2011, ISBN978-80-85990-18-8, CEMC (Ed.), Prague 10 National Standard, EN 50523-1, 2010 http://www.esmig.eu - European Smart Metering Industry Group, Smart Metering for Europe, Accessed on: 07/16/2011 Swede, M., Benes, P., Vrba, R.; Zezulka, F. (2005). Industrial Sensor Network, In: Handbook of Sensor Networks. Editors: M. Ilyas, I. Mahgoub, vol. 251 to 276, CRC Press, ISBN 0-8493-1968-4, London Jaroslav Authors:
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Zone4info - Power plant capacity and use factors
Power plant capacity and use factors Posted by Brown John August 6
What is Power Plant Capacity Factor It is defined as the ratio of actual energy produced in kWh to the maximum possible energy that could have been produced during the same period Plant Capacity Factor = E / (C x t) Where: E = Energy produced (kWh) in a given period C = Capacity of the plant in kW t = total number of hours in the given period Plant use Factor It is defined as the ratio of energy produced in given time to the maximum possible energy that could hav ebeen produced during the actual number of hours the plant was in operation. Plant use factor = E / (C x t1) Where: t1 = actual number of hours the plant has been in operation Prepared By: zone4info.com Reference: Power Plant Hand-Book
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Zone4info - Load Characteristics and types:
Load Characteristics and types: Posted by Brown John August 6
Load Characteristics and types: Total laod demand of an area depends upon its population and the living standards of people. General nature of load is characterized by the load factor, demand factor, diversity factor, power factor and utilization factor. In general, the types of load can be divided into the following categories: 1- Domestic 2- Commerical 3- Industrial 4- Agriculture Domestic Load:-
Demestic load mainly consist of lights, fans refrigerators, airconditioners, mixer, grinders, hearters, ovens, small pumping motors etc. Commercial Load:-
Commerical load mainly consists of lighting for shop, offices, advertisements etc, fans, heating, air-conditioning and many other electrical applicances used in commerical establishments such as market places, restaurants etc. Industrial Loads:
Industrial loads consists of small scale industries, medium scale industries, large scale industries, heavy industries and cottage industries.
Agriculture Loads:
This type of load is mainly motor pump sets load for irrigation purposes. Load factor for this load is very small e.g, 0.15 to 0.20. Prepared By: zone4info.com Reference: Power system book
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Zone4info - Reasons for interconnection of distribution systems
Reasons for interconnection of distribution systems Posted by Brown John August 6
Reasons for interconnection of distribution systems
Generating stations and distribution systems are connected through transmission lines. The transmission system of a particular area is known as a grid. Different grids are interconnected through tie-lines to form a regional grid (also called power pools). Different regional grids are further connecte to form a national grid. Cooperative assistance is one of the planned benefits of interconnected operation. Interconnected operation is always economical and reliable. Generating stations having large MW capacity are available to provide base or intermediate load. These generating stations must be interconnected so that they feed intor the general system but not into a particular load. Economic advantage of interconnection is to reduce the reserve generation capacity in each area. If there is sudden increase of load or loss of generation in one area, it is possible to borrow power from adjoining interconnected areas. To meet sudden increases in load, a certain amount of generating capacity (in each area) knows as the "spinning reserve" is required. This consists of generatos running at normal speed and ready to supply power instantaneously. It is always better to keep gas turbines and hydro generators as "spinning reserve". Gas turbines can be started and loaded in 3 minutes or less. Hdyro units can be even quicker. It is more economical to have certain generating stations serving only this function thant to have each station carrying its own spinning reserve. Interconnected operation also gives the flexibility to meet unexpected emergency loads. Prepared By: zone4info.com Reference: Power Plant Hand-Book
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Zone4info - Generating Station load factor and demand factor Calculation
Generating Station load factor and demand factor Calculation Posted by Zone 4info August 5
Maximum demand of a generating station is 80 MW and 150 MW is connected to it. If MWhr generated in a year are 400x103, determine 1. How to calculate the load factor 2. How to calculate the demand factor Solutions: Maximum Demand = 80 MW Connected load = 150 MW Units generated in one year = 400 x 103 MWhr Total number of hours in a year T = 8760 Average load = 400 x 103 / 8760 = 45.662 MW Load Factor, LF = Average load / Maximum Load LF = 45.662 / 80 = 0.57 Demand Factor, DF = Maximum demand / Connected Load DF = 80 / 150 = 0.533 Prepared By: Zone4info.com Reference: Power station Hand Book
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Power Station Load Supply Calculation
Power Station Load Supply Calculation
Posted by Zone 4info August 5
Example: A power station supplies the load as tabulated below: Time (hours) 6 AM TO 8 AM 8 AM TO 9 AM 9 AM TO 12 NOON 12 NOON TO 2 PM 2 PM â&#x20AC;&#x201C; 6 PM 6 PM TO 8 PM 8 PM TO 9 PM 9 PM TO 11 PM 11 PM TO 5 AM 5 AM TO 6 AM
Load (MW) 1.2 2.0 3.0 1.50 2.50 1.80 2.0 1.0 0.50 0.80
OBJECTIVES: 1- How to plot the load curve and find out the load factor. 2How to determine the proper number and size of generating units to supply this load. 3- How to find the reserve capacity of the plant and plant factor. 4- How find out the operating schedule of the generating units selected. Solution: (a) Plotting of load curve
Units generated during 24 hours = (2x1.2 + 1x2 + 3x3 + 2x1.5 + 4x2.5 + 2x1.8 + 1x2 + 2x1 + 6x0.5 + 1x0.8) MWhr. = 37.80MWhr Average Load = Units generated / time in hours Average Load = 37.80 / 24 = 1.575 MW Load Factor, LF = Average Load / Maximum Load Maximum Load = 3 MW LF = 1.575 / 3 = 0.525 (b) Maximum demand = 3 MW. Therefore, 4 generating units of rating 1.0 MW each may be selected. During the period of maximum demand 3 units will operate and 1 unit will remain as stand by (c) Plant capacity = 4 x 1.0 = 4.0 MW Reserve capacity = 4 â&#x20AC;&#x201C; 3 = 1 MW Plant Factor = (Actual energy produced) / (Maximum plant rating x T) Actual energy produced = 37.80 MWhr Maximum plant rating = 4 MW Time duration T = 24 hours Plant Factor = 37.80 / (4x24) = 0.39375 (d) Operating schedule will be as follows: One generating unit of 1 MW : -------- 24 hours Second generating unit of 1 MW: ------ 6 AM to 9 PM ( 15 hours) Third generating unit of 1 MW: 9 AM ------ 12 Noon, 2 PM â&#x20AC;&#x201C; 6 PM (7 hours) Prepared By: Zone4info.com Reference: Power system book
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Zone4info - How to reduce transformer noise using Epoxy or Polyurethane Compounds
How to reduce transformer noise using Epoxy or Polyurethane Compounds Posted by Crosslink Technology Inc. August 3
A novel way to reduce transformer noise using epoxy or polyurethane compounds Despite our very best efforts, at times we find that the transformer we built exceeds the maximum noise specifications. There are two major sources for transformer noise:
1. By far, the major cause of transformer noise is Magnetostriction.
Magnetostriction is the random movement of individual sheets within the stacked core. The individual sheets expand and contract, at different rates, as the core is magnetized. These extensions and contractions will occur twice during each complete cycle of the alternating current flowing through the coil.
2.
Mechanical vibration
This usually results from vibrations emanating from the core being transferred to everything else attached to it. Possible Fixes.... Read more about How to reduce transformer noise using epoxy or polyurethane compounds
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Zone4info - What is arc ?
What is arc ?
Posted by Mark David August 1
During opening of current carrying contacts in a circuit breaker the medium in between opening contacts become highly ionized through which the interrupting current gets low resistive path and continues to flow through this path even the contacts are physically separated. During the flowing of current from one contact to other the path becomes so heated that it glows. This is called arc.
Arc in Circuit Breaker
Whenever, on load current contacts of circuit breaker open there is an arc in circuit breaker, established between the separating contacts. As long as this arc is sustained in between the contacts the current through the circuit breaker will not be interrupted finally as because arc is itself a conductive path of electricity. For total interruption of current the circuit breaker it is essential to quench the arc as quick as possible. The main designing criteria of a circuit breaker is to provide appropriate technology of arc quenching in circuit breaker to fulfill quick and safe current interruption. So before going through different arc quenching techniques employed in circuit breaker, we should try to understand "e;what is arc"e; and basic theory of arc in circuit breaker, letâ&#x20AC;&#x2122;s discuss.
Thermal Ionization of gas There are numbers of free electrons and ions present in a gas at room temperature due to ultraviolet rays, cosmic rays and radioactivity of the earth. These free electrons and ions are so few in number that they are insufficient to sustain conduction of electricity. The gas molecules move randomly at room temperature. It is found an air molecule at a temperature of 300oK (Room temperature) moves randomly with an approximate average velocity of 500 meters/second and collides other molecules at a rate of 1010 times/second. These randomly moving molecules collide each other in very frequent manner but the kinetic energy of the molecules is not sufficient to extract an electron from atoms of the molecules. If the temperature is increased the air will be heated up and consequently the velocity on the molecules increased. Higher velocity means higher impact during intermolecular collision. During this situation some of the molecules are disassociated in to atoms. If temperature of the air is
further increased many atoms are deprived of valence electrons and make the gas ionized. Then this ionized gas can conduct electricity because of sufficient free electrons. This condition of any gas or air is called plasma. This phenomenon is called thermal ionization of gas.
Ionization due to electron collision As we discussed that there are always some free electrons and ions presents in the air or gas but they are insufficient to conduct electricity. Whenever these free electrons come across a strong electric field, these are directed towards higher potential points in the field and acquire sufficiently high velocity. In other words, the electrons are accelerated along the direction of the electric field due to high potential gradient. During their travel these electrons collide with other atoms and molecules of the air or gas and extract valance electrons from their orbits. After extracted from parent atoms, the electrons will also run along the direction of the same electric field due to potential gradient. These electrons will similarly collide with other atoms and create more free electrons which will also be directed along the electric field. Due to this conjugative action the numbers of free electrons in the gas will become so high that the gas stars conducting electricity. This phenomenon is known as ionization of gas due to electron collision
Deionization of gas If all the cause of ionization of gas are removed from an ionized gas it rapidly come back to its neutral state by recombination of the positive and negative charges. The process of recombination of positive and negative charges is known as deionization process. In deionization by diffusion, the negative ions or electrons and positive ions move to the walls under the influence of concentration gradients and thus completing the process of recombination.
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Why " parallel operation of transformers " is required ? Posted by Ashok Kumar August 1
This application guide addresses the limiting conditions of connecting transformers in parallel and loading considerations when turn ratios, impedances, and kVA ratings are different. Most transformers installed in parallel have the same kVA, turn ratios, and impedances, which can make it difficult for power engineers in industrial and commercial facilities to understand circulating currents and load sharing. However, as systems change over time, and transformers are replaced or added, users need to know the impact of paralleling transformers using different parameters. It is economical to installed numbers of smaller rated transformers in parallel than installing a bigger rated electrical power transformer. This has mainly the following advantages, 1) To maximize electrical power system efficiency: Generally electrical power transformer gives the maximum efficiency at full load. If we run numbers of transformers in parallel, we can switch on only those transformers which will give the total demand by running nearer to its full load rating for that time. When load increases we can switch no one by one other transformer connected in parallel to fulfill the total demand. In this way we can run the system with maximum efficiency. 2) To maximize electrical power system availability: If numbers of transformers run in parallel we can take shutdown any one of them for maintenance purpose. Other parallel transformers in system will serve the load without total interruption of power. 3) To maximize power system reliability: if nay one of the transformers run in parallel, is tripped due to fault other parallel transformers is the system will share the load hence power supply may not be interrupted if the shared loads do not make other transformers over loaded. 4) To maximize electrical power system flexibility: Always there is a chance of increasing or decreasing future demand of power system. If it is predicted that power demand will be increased in future, there must be a provision of connecting transformers in system in parallel to fulfill the extra demand because it is not economical from business point of view to install a bigger rated single transformer by forecasting the increased future demand as it is unnecessary investment of money. Again if future demand is decreased, transformers running in parallel can be removed from system to balance the capital investment and its return. Source: Transformer Handbook
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Zone4info - Types of RCD
Types of RCD
Posted by Johan column July 28
Residual current device (RCD) The instrument used for this test is an RCD tester, and it measures the time it takes for the RCD to interrupt the supply of current flowing through it. The value of measurement is either in seconds or milliseconds. Before we get on to testing, letâ&#x20AC;&#x2122;s consider what types of RCDs there are, what they are used for, and where they should be used. Types of RCD Voltage operated Voltage operated earth leakage current breakers (ELCBs) are not uncommon in older installations. This type of device became obsolete in the early 1980s and must not be installed in a new installation or alteration as they are no longer recognized by BS 7671. They are easily recognized as they have two earth connections, one for the earth electrode and the other for the installation earthing conductor. The major problem with voltage operated devices is that a parallel path in the system will probably stop it from operating. These types of devices would normally have been used as earth fault protection in a TT system. Although the Electrical Wiring Regulations BS 7671 cannot insist that all of these devices are changed, if you have to carry out work on a system which has one it must be replaced to enable certification to be carried out correctly. If, however, a voltage operated device is found while preparing a periodic inspection report, a recommendation that it should be replaced would be the correct way of dealing with it.
BS 4293 General purpose device These RCDs are very common in installations although they ceased to be used in the early 1990s. They have been replaced by BS EN 61008-1, BS EN 61008-2- 1 and BS EN 61008-2-2. They are used as standalone devices or main switches fitted in consumersâ&#x20AC;&#x2122; units/distribution boards. This type of device provides protection against earth fault current. They will commonly be found in TT systems 15 or more years old, although they may be found in TNS systems where greater protection was required. If this type of device is fitted to a TT system which is being extended or altered, it is quite safe to leave it in the system. If the system supplies socket outlets which could be used to supply portable equipment used outside, it must have a tripping current of no more than 30 mA. This includes socket outlets that could serve extension leads passed through open windows or doors. The problem with using a low tripping current device as the main switch is that nuisance tripping could occur. The modern way of tackling this is explained later in this topic
BS 4293 Type S These are time delayed RCDs and are used to give good discrimination with other RCDs. BS EN 61008-1 General purpose device This is the current standard for a residual current circuit breaker (RCCB) and provides protection against earth fault current. These devices are generally used as main switches in consumersâ&#x20AC;&#x2122; units/distribution boards. Three-phase devices are also very common.
BS 7288 This is the current standard for RCD-protected socket outlets and provides protection against earth fault currents. These socket outlets would be used in areas where there is an increased risk of electric shock, such as common areas of schools and colleges. It is also a requirement that any socket outlet used for portable equipment outdoors must have supplementary protection provided by an RCD (Regulation 47116-02). Where the socket outlets are sited outside, waterproof BS 7288 outlets are used to IP 56.
BS EN 61009-1 This is the standard for a residual current circuit breaker with overload (RCCBO) protection. These devices are generally used to provide single circuits with earth fault protection, overload protection and short circuit protection. They are fitted in place of miniature circuit breakers and the correct type should be used (types B, C or D). BS EN 61008-1 Type S These are time delayed RCDs and are used to give good discrimination with other RCDs. Section 3 of the On-Site Guide gives good examples of how these devices should be used within an installation. RCDs and supply systems TT system If the installation is a TT system and it is possible for any of the sockets to supply portable equipment outdoors or RCD protection is required for other
reasons (protection for fixed equipment in zones 1-3 in bathrooms, for instance), there are various options available. While all will be safe, they will vary in cost. Option 1 Use a 100 mA S-Type RCD (BS EN 610081) as the main switch and RCD protection for all circuits. Then use a 30 mA RCBO (BS EN 61009) as a circuit protective device for the circuit which requires protection. In this case, the 100 mA RCD must be labelled â&#x20AC;&#x2DC;Main Switchâ&#x20AC;&#x2122;. Option 2 Use a split board with 100 mA S-Type RCD (BS EN 61008) as a main switch and a 30 mA RCD (BS EN61008). All circuits require supplementary protection. This method is useful if more than one circuit requires 30mA protection.
Option 3 Use a split board with a 100 mA RCD for fixed equipment and lighting with a 30 mA RCD for the circuits requiring supplementary bonding. This option would require a separate main switch. Option 4 Another method would be to use a consumer unit with a main switch to BSEN 60947-3 and RCBOs to BS EN 610091 as protective devices for all circuits. This option is perfectly satisfactory but can work out a little expensive! TNS and TNCS systems If the supply system was TNS or TNCS, Options 1 and 2 could be used. But instead of using a 100 mA S-Type RCD as a main switch, it could be substituted for a main switch to BS EN 60947-3. Option 4 will remain pretty much the same but BS EN 60898 devices could be used where RCD protection is not required. Testing of RCDs Remember that these are live tests and care should be taken whilst carrying them out The instrument to be used to carry out this test is an RCD tester, with leads to comply
with GS 38. Voltage operated (ELCBs) No test required as they should now be replaced. BS 4293 RCDs If this type of RCD is found on TT systems or other systems where there is a high value of earth fault impedance (Ze), the RCD tester should be plugged into the nearest socket or connected as close as possible to the RCD. The tester should then be set at the rated tripping current of the RCD (I n); for example, at 30 mA (be careful and do not mistake the tripping current for the current rating of the device). Source: Practical Guide to Inspection, testing and certificate of electrical installation by Christropher Kitcher Prepared By: Zone4info.com Team
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Zone4info - Basics of Power Monitoring
Basics of Power Monitoring Posted by Johan column July 27
Direct Current (DC) The supply of current for electrical devices may come from a direct current (DC) source or an alternating current (AC) source. As discussed in the Basics of Electricity course, electric utilities generate and distribute AC power. However, there are many sources and uses of DC power as well. DC power sources include a variety of devices such as solar cells, batteries, electronic circuits that convert AC to DC, and DC generators. In a DC circuit, electrons flow continuously in one direction from the source of power through a conductor to a load and back to the source of power. Voltage polarity for a direct current source remains constant.
Alternating Current (AC) An AC generator makes electrons flow first in one direction then in another. In fact, an AC generator reverses its terminal polarities many times a second, causing current to change direction with each reversal. Alternating voltage and current vary continuously. The graphic representation for AC is a sine wave. A sine wave can represent current or voltage. The accompanying illustration shows one cycle of a sine wave on a graph with two axes. The vertical axis represents the direction and magnitude of current or voltage. The horizontal axis represents time. When the waveform is above the time axis, current is flowing in one direction. This is referred to as the positive direction. When the waveform is below the time axis, current is flowing in the opposite direction. This is referred to as the negative direction. A sine wave moves through a complete rotation of 360 degrees, which is referred to as one cycle. As will be discussed later in this course, a typical AC sine wave goes
through many of these cycles each second.
Frequency The number of cycles per second of voltage and current produced by an AC generator is referred to as the frequency of that voltage and current. The recognized unit for frequency is hertz, abbreviated Hz. 1 Hz is equal to 1 cycle per second. Power companies generate and distribute electricity at very low frequencies. The standard power line frequency in the United States and many other countries is 60 Hz. 50 Hz is the other common power line frequency used throughout the world. The following illustration shows 15 cycles in 1/4 second. This is equivalent to 60 Hz. Although power companies generate electricity at a low fixed frequency, many electronic circuits convert this low frequency to a higher frequency or a variable frequency for use in a variety of ways. Frequency is an important characteristic of AC because many devices and circuits respond differently to different frequencies.
Amplitude Voltage and current in an AC circuit rise and fall over time in a pattern referred to as a sine wave. As previously discussed, one complete sine wave is referred to as a cycle, and the number of cycles in one second is referred to as the frequency. In addition to frequency, an AC sine wave also has amplitude, which is the range of variation from its maximum value to its minimum value. Amplitude can be specified in three ways: peak value, peak-to-peak value, and effective value. The peak value of a sine wave is the maximum value for each half of the sine wave.
The peak-to-peak value is the range from the positive peak to the negative peak. This is twice the peak value. The effective value of AC is defined in terms of an equivalent heating effect when compared to DC. Instruments designed to measure AC voltage and current usually display the effective value. The effective value of an AC voltage or current is approximately equal to 0.707 times the peak value. The effective value is also referred to as the RMS value. This name is derived from the root-mean-square mathematical process used to determine the effective value of a waveform.
Instantaneous Value The instantaneous value is the value at any one point on the sine wave. The voltage waveform produced as the armature of a basic two-pole AC generator turns through one full 360 degree rotation is called a sine wave because the instantaneous voltage or current is related to the sine trigonometric function. As shown in the accompanying illustration, the instantaneous voltage (e) and current (i) at any point on the sine wave is equal to the peak value times the sine of the angle. The sine values shown in the illustration are obtained from trigonometric tables. Keep in mind that each point has an instantaneous value, but this illustration only shows the sine of the angle at 30 degree intervals.
Three-Phase Power
Up till now, we have been talking only about single-phase AC power. Single-phase power is used where power demands are relatively small, such as for a typical home. However, power companies generate and distribute three-phase power. Three-phase power is used in commercial and industrial applications where power requirements are higher than those of a typical residence. Three-phase power, as shown in the accompanying illustration, is a continuous series of three overlapping AC cycles. Each wave represents a "phase" and is offset by 120 electrical degrees from each of the two other phases. The three phases are referred to as Phases A, B, and C.
Phase Rotation As previously described, the phase relationships for the typical three-phase AC voltage or current supplied by a power company can be shown using waveforms plotted on a graph. However, this relationship can be described more simply with a diagram showing three phase vectors. The length of each vector represents the amplitude of one of the phases. Each of these vectors is separated from the other two vectors by 120 degrees. When the three-phase AC voltage is applied to the stator of a three-phase motor, a rotating magnetic field is produced. The arrow on the phase diagram in this example is used to show the direction of rotation for this magnetic field. Phasor diagrams, like the one shown in the lower right corner, are available on many Siemens power meters.
Linear Loads Electrical equipment loads can be either linear or non-linear. It is important to understand the differences between these two types of loads and how these types of loads affect power quality. A linear load is any load in which voltage and current increase or decrease proportionately. Voltage and current may be out of phase in a linear load, but the waveforms of each are still sinusoidal and proportionate. Motors, resistive heating elements, incandescent lights, and relays are examples of linear loads. Linear loads can cause a problem in a distribution system if they malfunction or are oversized for the distribution system. However, when operated within specifications, they do not cause harmonic distortion, a type of waveform distortion which will be discussed later. Power monitoring systems are important for use with all types of loads. For example, they can identify when load currents are approaching levels that will cause an overload and trip overcurrent protection devices. Power monitoring devices can be used on feeder and branch circuits as well as on distribution system mains. For example, they can be used to monitor individual loads. LEED certification, developed by the U. S. Green Building Council, even requires HVAC and lighting over a certain amperage to be monitored individually for compliance.
Non-linear Loads When instantaneous load current is not proportional to instantaneous voltage, the load is considered a non-linear load. Computers, televisions, PLCs, ballasted lighting, variable speed drives, and a variety of devices with electronic power supplies are examples of nonlinear loads. Non-linear loads can distort waveforms, but the exact amount and type of distortion varies depending on the load. The waveform that you see when you mouse over the red rectangle is only one example of a distorted three-phase current waveform. A good power quality monitoring systems is essential to maintaining a power distribution system that provides clean power. Applying the wrong solution can be costly and dangerous.
Harmonics Many electronic circuits and devices produce frequencies which are multiples of the applied frequency. Any frequency produced which is a multiple of the original frequency is called a harmonic. The original frequency is referred to as the fundamental or base frequency or the first harmonic. Each frequency multiple is referred to by its number. For example, the second harmonic is twice the fundamental frequency, the third harmonic is three times the fundamental frequency, etc. Circuits that produce harmonics usually produce them at reduced amplitudes from the fundamental frequency. In addition, these circuits do not produce every harmonic multiple, but the specific harmonics produced depend on the type of circuit and the power levels involved. Harmonic effects can show up as heat in various places such as apparatus neutrals, transformer, and capacitor banks. When the heat builds up sufficiently, equipment is damaged. Power monitoring systems can identify harmonics and their sources to enable corrections.
Source: siemens. Prepared By: Zone4info.com
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Zone4info - Instrument Transformers
Instrument Transformers Posted by Brown John July 26
Instrument Transformers Instrument transformers facilitate the measurement of high voltages and currents using very accurate standard low range voltmeters and ammeters. They also provide the safety in making measurements by electrically isolating meters from the primary circuits. Potential (Voltage) transformers (PT, VT)
Potential transformer is a step down type transformer: Many turns on the primary winding connected to the HV circuit and few turns on the secondary winding, which is connected to the measuring instrument. Magnetic core of a potential transformer is usually shell type to provide better accuracy. One end of the secondary winding is usually grounded to provide adequate protection to the operator. Since the voltmeter behaves like an open circuit, the output current is almost zero: the power rating of the potential transformer is very low. Current transformers (CT)
CT with a wound primary
Clip-on type CT Current transformer is designed to measure high currents in power systems. Primary has few winding of heavy wire; Secondary has many turns of fine wire. In clamp-on type current transformers, the current carrying conductor it self act as one-turn primary. Low range ammeter is connected across the secondary winding. Ammeter has very low impedance, and practically acts as a short circuit. Magnetizing current is almost negligible, and flux density is relatively low. Consequently, CT core is never saturated under normal operating conditions. A CT is designed to operate with a short circuited (or very low impedance) secondary winding. It should never be left open. If the secondary is left open, the primary winding is still carrying a current (primary circuit current do not depend on the CT burden). Since there is no secondary current to counteract its emf, core flux may increases to very high level. As a result, a dangerously high voltage can induced on the secondary side. Ratio and phase angle errors introduced by the instrument transformers must be minimized. Therefore, they are designed to approximate the ideal transformers as closely as practical. Prepare By: Zone4info.com Team Source: ECE 3650 / Dr. Athula Rajapakse
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Zone4info - Smart metering of electricity is not convenient for all customers
Smart metering of electricity is not convenient for all customers Posted by Mark David July 22
A smart meter electricity consumption does not always bring so much energy savings, what they expect from them, found the European Association of Consumer Unions. For some customers it may be said to intelligent systems even disadvantageous. Concerns relate to the protection of sensitive data that will be in the hands of energy companies. By 2020 it should have at least 80% of European consumers' implementation of intelligent metering systems energy consumption. They are able to obtain data from end users, thus allowing to monitor consumption to increase energy efficiency. The Energy Performance of Buildings by EU member states required to draw up national plans for their implementation. To 3 September this year would, therefore, member states should have processed the economic assessment for the implementation of smart metering to transmission systems. One of the main consequences of the use of smart meters should be saving energy and thus the costs for end consumers. Energy companies because they will be able to offer flexible rates and payments to households to implement energy-saving technology.
Useful only for some
European Association of Consumer Unions (BEUC) has recently published a study of the Free University of Brussels, which shows that customers are not always those with the use of this technology, the greatest benefit. "Smart meters are convenient for some customers. However, we doubt that they are beneficial for all customers, "says Johannes Klein from BEUC." We are against the mandatory introduction of smart metering for all consumers, "said another expert from BEUC Monika Ĺ tajnarovĂĄ. It could for example, is said to harm the customers who already consume minimum electricity for only the most basic purposes. Office of the European Data Protection Supervisor (EDPS) is also concerned that energy suppliers would be able to exploit the high amount of personal data, which, thanks to smart metering system gain. Only the energy companies and said it will depend whether the individual customers choose to assist in saving or not. This could lead to price discrimination.
Not so big savings
National evaluation of the impact of smart metering, which are still available, also indicate questionable estimates of potential savings. The European Commission has introduced smart meters about 10% of households in the EU. These consumers are said to be able to achieve savings of around 10% or more. In the UK, customers by
way of Alert control your appliances such as a mobile phone. Because of this, supposedly able to save up to 40% of electricity. According to data from Spain saves customers through intelligent systems about 15% of energy. BEUC, however, studied six analyzes commissioned by the major European energy companies, including EDF and E.ON These studies have shown that if customers opt for smart meters, they will save only about 2-4% of energy. Source: google.com
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Zone4info - Zig-Zag Transformer and Transformer Vector Groups
Zig-Zag Transformer and Transformer Vector Groups Posted by Johan column July 21
A zigzag winding is a series connection of two windings whose voltages are 600 out of phase. The two windings are typically the same voltage magnitude, but custom phase shifts can be created if the voltage magnitude of the two windings differs. There are two basic ways to create a zigzag winding: â&#x20AC;˘ Connect the A leg in series with B leg (called a ZAB) â&#x20AC;˘ Connect the A leg in series with C leg (called a ZAC) The polarity marks of the two windings either face toward one another or face away from one another. The connection diagram for a ZAC zig-zag winding is shown below.
The Zig-Zag transformers which have only a primary windings but no secondary winding are used to derive an earth reference point for an ungrounded electrical system. Another application is to control harmonic currents.
Transformer Vector Groups It is possible to connect three-phase transformers to achieve different phase shifts between the primary and secondary sides. For example, -Y transformer, which usually has a +30o phase shift in the secondary corresponding to primary side, can be connected to achieve a -30o phase shift as shown below.
According to IEC standards, this connection is denoted as Dy1 connection. The ‘D’ indicates delta primary, ‘y’ indicates wye connected secondary and ‘1’ indicates a 30o phase shift in secondary phase voltages relative to primary phase voltages. The number ‘1’ comes from the fact that primary and secondary phase-A voltage vectors when plotted together indicate clock position ‘1’. The following table gives different vector groups of -Y and YΔ transformers.
Common transformer connections and their vector groups
In North America, it is customary to make the secondary voltage lag the primary voltage. According to ANSI Standards (ANSI/IEEE Std C57.70).: • High voltage terminals are marked with H1, H2 and H3 (or A,B, and C ). • Low voltage terminals are marked with X1, X2 and X3 (or a, b, and c ). The American Standards for labeling of the windings states that “In either a Y- or ΔY transformer, positive-sequence quantities on the HV side shall lead their corresponding quantities on the low voltage side by 30o.” Thus in the three-phase Yor Δ-Y transformers manufactured according to American Standards, the HV side voltages are always leading the LV side voltages, regardless of the HV winding connection type. Instead of the vector group, the name plate provides a vector
diagram such as the one shown below.
The above transformer example has the vector group Dy1. Source: ECE 3650 / Dr. Athula Rajapakse Prepared By: Zone4info.com Team
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Zone4info - THREE-PHASE OIL IMMERSED EARTHING TRANSFORMERS
THREE-PHASE OIL IMMERSED EARTHING TRANSFORMERS Posted by Johan column July 19
Application Earthing transformers are applied in power networks for getting an artificial neutral point to which arc-suppression reactor or resistor is connected. The transformers are three-phase and are used for substation auxiliary supply (self service) in case when power network is not earthed. When failure occurs in power network transformers are energised with phase voltage in neutral point. During transformer operation HV terminals are connected to power network and 1N neutral point is connected to terminal 1A of arc-suppression reactor or resistor. Transformers can be loaded with continuous power of auxiliary supply. HV winding can be simultaneously loaded with compensating earthing current at secondary winding loaded with continuous rated power. Operational condition Transformers in basic execution are suitable to operate in moderate climates. They can operate outdoors in location of altitudes up to 1,000 metres above sea level or indoors with sufficient ventilation, where ambient air is free from dust and chemically active or explosive gases. Ambient temperature range is from -25°C to +40°C (248°K to 313°K), annual average temperature should not exceed +20°C (293°K). The Manufacturer offers also transformers subject to client requirements, for instance for operation in tropic climate.
Operational frequency 50 Hz. Loading conditions are shown in the Table below: Compensating current as % of rated current 100 87.5 75 62.5 50 General description
Permissible operational period in hours 2 4 8 continuous operation continuous operation
Transformer core consists of three columns and is manufactured from cold-rolled electromagnetic steel sheet with non-organic insulation layer. Sheets in core columns are glued or tied and yoke sheets are tied with glass band. Windings are made of electrolytic copper and used conductors are round with enamel insulation or profile insulated by means of insulating paper. There are oil ducts among winding which provide oil circulation and proper cooling. Winding design and fastening ensure very high dielectric and arc insulation withstand and short-circuit capacity. HV winding has taps for voltage regulation. Voltage regulation range equals to ±5%. Tap changer is installed in transformers main tank and it has manual regulation wheel on tank cover. Regulation of transformer ratio (by means of changing taps) is made after switching transformer off-voltage. Tap changer has blocking facility for each tap position. Transformer windings are connected in ZNyn11 connection group. Transformer main tank is made of steel and its welded construction is reinforced by means of supports increasing rigidity and proper mechanical withstand. Cooling of transformers is performed by means of steel sheet radiators fixed in position to the main tank wall. Transformer main tank has undercarriage with bi-directional wheels. Accessories • • • • • • • •
4 porcelain bushings of HV side, placed on transformer main tank cover 4 porcelain bushings of LV side, placed on transformer main tank cover Maximum thermometer Buchholza relay Conservator with Oil level indicator Earthing bolts Oil draining and filling valves Nominal plates
Accessories of each transformer are in compliance with Dimensional Drawing. Tolerance In accordance with bending Standards tolerance for transformer ratings are as follows: • No-load loss: +15% • Load loss: +15% • Total loss: +10% • No-load current: +30% • Impedance voltage: ±10% Reference Standards and International Provisions EN 60289 - Reactors. (IEC Publication No. 289) EN 60076-1 - Power Transformers. (IEC Publication No. 76.1)
Source: www.ftz.com.pl
Take Print Zone4info - Why is the rating of transformers given in kVA and not in kW?
Why is the rating of transformers given in kVA and not in kW? Posted by Brown John July 17
kVA is the unit for apparent power. Apparent power consists of active and reactive power. Active power is the share of the apparent power which transmits energy from the source (generator) to the user. Reactive power is the share of the apparent power which represents a useless oscillation of energy from the source to the user and back again. It occurs when on account of some »inertia« in the system there is a phase shift between voltage and current. This means that the current does not change polarity synchronous with the voltage. But the heat generated in a winding as well as the eddy current losses generated in a transformer core depend on the current only, regardless of whether it aligns with the voltage or not. Therefore the heat is always proportional to the square of the current amplitude, irrespective of the phase angle (the shift between voltage and current). So a transformer has to be rated (and selected) by apparent power. It is often helpful to think of an extreme example: Imagine a use case where the only and exclusive load is a static var compensator (and such cases do exist). Would the load then be zero because the active power is zero? Most certainly not. – Caution: In this situation the voltage across the output terminals will increase with load rather than drop! Supplement: Special care has to be taken if the load current of a transformer includes any higher frequencies such as harmonics. Then the transformer may even overheat although the TRMS load current, measured correctly with a TRMS meter, does not exceed the current rating! Why is this? It is because the copper loss includes a share of about 5% to 10% of so-called supplementary losses. These arise from eddy currents in mechanical,
electrically conductive parts made of ferromagnetic materials and especially in the low voltage windings with their large cross sections. The magnetic stray fields originating from a lack of magnetic coupling between the HV and LV windings (main stray canal) induce something that could be called an “eddy voltage” inside the conductors, which drives an eddy current flowing around in a circle across the conductor, perpendicular to the main load current. Now the amplitude of this “eddy voltage” is proportional to the rate of change of the magnetic field strength. The rate of change of the magnetic field strength is proportional to both the amplitude and the frequency of the current. So the eddy current increases proportionally to the load current and proportionally to the operating frequency, for the limitation to the eddy current is Ohm’s Law. The supplementary power loss caused by the eddy current is eddy current times “eddy voltage”. Hence, the supplementary losses increase by the square of the load current, which excites the magnetic stray field, and by the square of the frequency, while the “main copper loss” increases only by the square of the load current amplitude. Therefore the transformer runs hotter when the load current has the same amplitude but is superimposed by higher frequency constituents above the rated frequency. This additional heat loss is difficult to quantify, especially as the transformer’s stray reactance limits the passage of higher frequency currents to some extent, but in an extreme case it may drive the supplementary loss up from 10% to 80% of the copper loss. This means that the transformer may run some 70% hotter (of temperature rise above ambient) than specified for rated (sinusoidal) current. Since the ohmic heat loss, however, depends on the square of the current, it is enough to limit the load current to some 65% of its rating to avoid overheating. Source: http://www.leonardo-energy.org
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Zone4info - Why choose a solar electric system?
Why choose a solar electric system? Posted by Johan column July 16
Why choose a solar electric system? There are a number of reasons to consider installing a solar electric system: • Where there is no other source of electrical power available, or where the cost of installing conventional electrical power is too high • Where other sources of electrical power are not reliable. For example, when power cuts are an issue and a solar system can act as a cost-effective contingency • When a solar electric system is the most convenient and safest option. For example, installing low voltage solar lighting in a garden or providing courtesy lighting in a remote location • You can become entirely self sufficient with your own electrical power • Once installed, solar power provides virtually free power without damaging the environment Cost-justifying solar Calculating the true cost of installing a solar electric system depends on various factors: • The power of the sun at your location at different times of the year • How much energy you need to generate • How good your site is for capturing sunlight Compared to other power sources, solar electric systems typically have a comparatively high capital cost, but a low ongoing maintenance cost. To create a comparison with alternative power sources, you will often need to calculate a payback of costs over a period of a few years in order to justify the initial cost of a solar electric system. On all but the simplest of installations, you will need to carry out a survey on your site and carry out some of the design work before you can ascertain the total cost of installing a photovoltaic system. Do not panic: this is not as frightening as it sounds. It is not difficult and I cover it in detail in later chapters. We can then use this figure to put together a cost-justification on your project to compare with the alternatives.
Solar power and wind power Wind turbines can be a good alternative to solar power, but probably achieve their best when implemented together with a solar system: a small wind turbine can generate electricity in a breeze even when the sun is not shining. Small wind turbines do have some disadvantages. Firstly, they are very site-specific, requiring higher than average wind speeds and minimal turbulence. They must be higher than surrounding buildings and away from tall trees. If you live on a windswept farm or close to the coast, a wind turbine can work well. If you live in a built-up area or close to trees or main roads, you will find a wind turbine unsuitable for your needs. Compared to the large wind turbines used by the power companies, small wind turbines are not particularly efficient. If you are planning to install a small wind turbine in combination with a solar electric system, a smaller wind turbine that generates a few watts of power at lower wind speeds is usually better than a large wind turbine that generates lots of power at high wind speeds. Fuel cells Fuel cells can be a good way to supplement solar energy, especially for solar electric projects that require additional power in the winter months, when solar energy is at a premium. A fuel cell works like a generator. It uses a fuel mixture such as methanol, hydrogen or zinc to create electricity. Unlike a generator, a fuel cell creates energy through chemical reactions rather than through burning fuel in a mechanical engine. These chemical reactions are far more carbon-efficient than a generator. Fuel cells are extremely quiet, although rarely completely silent, and produce water as their only emission. This makes them suitable for indoor use with little or no ventilation. Grid-tied solar electric systems Grid-tied solar electric systems connect directly into the electricity grid. When the sun is shining during the day, excess electricity feeds into the grid. During the evening and night, when the solar panels are not providing sufficient power, electricity is taken from the grid as required. Grid-tied solar electric systems effectively create a micro power station. Electricity can be used by other people as well as yourself. In some countries, owners of gridtied solar electric systems receive payment for each kilowatt of power they sell to the electricity providers. Because a grid-tied solar electric system becomes part of the utility grid, the system will switch off in the event of a power cut. It does this to stop any current flowing back into the grid, which could be fatal for engineers repairing a fault. Solar electricity and the environment Once installed, a solar electric system is a low-carbon electricity generator: the sunlight is free and the system maintenance is extremely low. There is a carbon footprint associated with the manufacture of solar panels, and in the past this footprint has been quite high, mainly due to the relatively small
volumes of panels being manufactured and the chemicals required for the ‘doping’ of the silicon in the panels. Thanks to improved manufacturing techniques and higher volumes, the carbon footprint of solar panels is now much lower. You can typically offset the carbon footprint of building the solar panels by the energy generated within 2–5 years, and some of the very latest amorphous thin-film solar panels can recoup their carbon footprint in as little as six months. Therefore, a solar electric system that runs as a complete stand-alone system can reduce your carbon footprint, compared to taking the same power from the grid. Grid-tied solar systems are slightly different in their environmental benefit, and their environmental payback varies quite dramatically from region to region, depending on a number of factors: • How grid electricity is generated by the power companies in your area (coal, gas, nuclear, hydro, wind or solar) • Whether or not your electricity generation coincides with the peak electricity demand in your area (such as air conditioning usage in hot climates, or high electrical usage by nearby heavy industry) It is therefore much more difficult to put an accurate environmental payback figure on grid-tied solar systems. It is undeniably true that some people who have grid-tied solar power actually make no difference to the carbon footprint of their home. In colder climates, the majority of electricity consumption is in the evenings and during the winter. If you have grid-tie solar but sell most of your energy to the utility companies during the day in the summer and then buy it back to consume in the evenings and in the winter, you are making little or no difference to the overall carbon footprint of your home. In effect, you are selling your electricity when there is a surplus and buying it back when there is high demand and all the power stations are working at full load. In warmer climates, solar energy can make a difference. In a hot area, peak energy consumption tends to occur on sunny days as people try to keep cool with air conditioning. In this scenario, peak electricity demand occurs at the same time as peak energy production from a solar array, and a grid- tie solar system can be a perfect fit. If you live in a colder climate, this does not mean that there is no point in installing a grid-tie solar system. It does mean that you need to take a good hard look at how and when you consume electricity. Do not just assume that because you can have solar panels on the roof of your house, you are automatically helping the environment. From an environmental perspective, if you wish to get the very best out of a grid-tie system, you should try to achieve the following: • Use the power you generate for yourself • Use solar energy for high load applications such as clothes washing • Reduce your own power consumption from the grid during times of peak demand Environmental efficiency: comparing supply and demand There is an online calculator that will allow you to map your electricity usage over a period of a year and compare it with the amount of sunlight available to your home. Designed specifically for grid-tie installations, this calculator allows you to see how close a fit solar energy is in terms of supply and demand. Whilst this online calculator is no substitute for a detailed electrical usage survey and research into the exact source of the electricity supplied to you at your location, it will give you a good indication of the likely environmental performance of a solar energy system. Source: Solar Electricity HandBook Prepared By: zone4info.com
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Zone4info - THERMAL PERFORMANCE OF POWER TRANSFORMERS
THERMAL PERFORMANCE OF POWER TRANSFORMERS Posted by Johan column July 16
SUMMARY For a generator transformer or sub-station unit, the operating conditions are very different. They lead to specific thermal performance requirements as regards to either ageing aspect or overload. The evolutions of the electricity market have introduced new needs for technical and economic optimisation generally leading to operate the equipment in a different way or for a longer period of time. At the same time the manufacturers have made progress in thermal design control. They have developed new calculation tools based either on simple analytical methods or thermal modelling. This report illustrates with several examples the new needs of users and the calculation tool progress made by manufacturers enabling them to master all these evolutions. Transformer - Overload - Ageing - Modelling - Specification - Design - Optic fibre 1. ISSUES OF THERMAL PERFORMANCE CONTROL FOR SYSTEM AND POWER COMPANIES 1.1. Sub-station Transformers on RTE’s Transmission Network The power transformers and auto-transformers account for approximately 10% of the permanent assets of RTE. It is thus significant to optimise their use in order to differ purchase and installation from additional transformers or to avoid the replacement of existing transformers by more powerful equipment. Two types of events are taken into account to decide to increase the capacity of transformation : - technical event : It corresponds for example to the unavailability of one transformer, which may result in transmitting the maximum power flow of the substation through a reduced number of transformers. Severe climatic conditions are not taken into account in this case. In such a situation one authorizes the transformers to be overloaded for a long duration with a current limited to Ild, or for a short duration, limited to Is. This degraded mode is generally noted “N-1 situation”. - climatic event : It corresponds to the supply of the maximum power, which may be called during a cold spell of winter, all the network being available. In this mode, noted “N situation”, one considers that each apparatus forwards only its rated current Ir. The choice of Ild and Ir values is essential to optimise the park of transformers. The definition of the loading limits for substation transformers used currently within RTE
today, was carried out in the Sixties. Indeed several normative evolutions came at that time: in 1962 French standard NFC 52-100 brought to 75 K (against 70 K before) the maximum temperature rise of the hottest spot in steady state operation at rated current. In addition the IEC loading guide published in 1968 limited the hot spot temperature during exceptional transient overloads at 140°C.
Figure 1 : Limitations for sub-station transformers overloads From this maximum hot spot temperature of 140° C, new operating rules [1 ] were defined for the overloads of the substation transformers. These rules summarized in Figure 1 consider two types of overload : long-time emergency overloads (Ild): Under the degraded operation of the system, transformers can be submitted to overloads of limited magnitude over long durations. As the highest loaded periods of the network in France are in winter-time two levels of long-time overloads were defined according to the ambient temperature : Ild = 1.15 Ir for an ambient temperature lower than 30°C and Ild = 1.25 Ir for ambient temperature lower than 15°C. Later on, a third threshold of 1.35 Ir was introduced for ambient temperature lower than 5°C following the periods of great cold met during winter 86-87. - Short-time emergency overloads (Is): Sudden failure of a system element leads to larger overloads in transformers, that is to say up to Is=1.5 Ir. The transformer is not designed to withstand such a level of overload without damage over a long period, but over the time needed for the network to be operated (topology, generation, loads). A 20 minutes duration was defined for the 220/90 kV or 220/63 kV transformers for which the occurrence of high overloads are low, since the 63 and 90 kV networks are usually not meshed. Furthermore, the operation of the 400 kV transformers between Ild and Is is authorized during 20 minutes only if the top oil temperature does not exceed a predetermined value “TL” when the current reaches Ild. Beyond Is, tripping of the transformer occurs automatically after 5mn. This temporisation used to be fixed at 20 seconds before the Eighties. 1.2. Generator step-up transformers at EDF’s nuclear power stations This equipment is made up of single-phase unit banks, the rated powers of which are in respect of generator power, namely either 360MVA for 1120MVA generators of 900MW power stations or respectively 550 and 570MVA for 1650 and 1710MVA generators of 1300 and 1400MW power stations. These transformers produce on 400kV interconnection network and their low voltage level is either 24 or 20kV on the generator side. For this equipment, the slightest failure during production periods, means costs incurred as a consequence of loss of production. These costs are much greater than the replacement cost of the failed unit. The impact would be significant in the event of established generic default. Therefore, these transformers are required a high level of reliability. The first manufacturing generations were specified with acceptance tests in seventies, in particular a full temperature-rise test. The later equipment was still constructed with the same design as the first generation power transformers One of the design features for the total of 174 single-phase transformers is to operate most of the time at higher loads, close to their specifications duty. Another feature of all these transformers is that their commissioning spread over a period of 20 years (1975 –1995), which is, a short period when compared to the usual transformer life expectancy.
As regards the technology, this equipment is specified with ODAF type cooling and will comply with the same requirements, such as average temperature rise and hotspot temperature rise, as for the sub- station transformers. These performances have to be respected with reference to rated power and for each of 3 de-energized type taps, at 30°C ambient temperature. The minimum cumulative lifetime of operation is set to 200 000 hours, for reference hotspot temperature value of 105°C. Some exceptional duties are also specified, which correspond to a maximum cumulative duration of 5 hours, but which will lead to hotspots lower than 120°C. Supplying of new spare transformers is subjected to identical specifications, except for life expectancy, which is extended to 40 years. 2.
ISSUES FOR THE MANUFACTURERS
The technical and economic issues of the optimisation of the thermal design for transformers and particularly for large power transformers are well known. This has given scope for a large number of theoretical and experimental research by the manufacturers and by the users [2]. Regarding the use, we are beginning to accumulate a large amount of data on apparatus which have been in service for many years. In the frame of a partnership between manufacturers and users, this may allow the confrontation between the life durations as estimated theoretically and the field observations. In any case, the accurate knowledge of the temperatures reached within the transformer, and particularly, the knowledge of the temperature reached by the hottest spot within the windings enables the manufacturers to come up with the most reliable design, regarding a given assigned life duration of the insulations. Such a knowledge requires a good understanding of the principles of the generation and of the dissipation of the heat in transformers. That is translated into thermal software with varying levels of detail. 2.1. Control of the heat sources Today, the manufacturers are equipped with powerful calculation tools to determine the losses, and in particular, the winding stray losses with a good accuracy. Furthermore, some solutions allow to treat and to reduce the losses. The following examples can illustrate this point : - to reduce the no-load losses : elaborate techniques for the magnetic steel sheet cutting and stacking (step lap core) - for the load losses : use of continuously transposed cables (CTC) or permutation techniques, use of magnetic shielding or conducting plate shielding. Thus, all the heat sources are under control. 2.2. Control of the temperature rise For a given technology, each manufacturer has developed theoretical and empirical methods for the determination, not only of the average temperature rise of oil and of copper, but also for the assessment of the hottest spot of the windings (See examples given in §4). To act on the thermal performance of large power transformers, the aim is to achieve a sufficient oil flow in every part of the magnetic circuit and of the windings. Various well known techniques are being optimised by the manufacturers for a long time : - cooling ducts for the windings and, if necessary, for the magnetic circuit forced and/or directed oil flow to improve the thermal exchange between the windings and the oil - zigzag oil flow in ONAN (for core type transformers with disk type coils) …etc. As an illustration, Figure 2, schematically gives an example of oil flow for a shell type transformer with ONAN type cooling.
2.3. Use of more high-temperature materials In addition to the solutions mentioned above, some high-temperature electrical insulation materials can be used for the solid insulation and also for the dielectric liquids (full insulation or hybrid insulation). That is the topic of the draft standard IEC 60 076-14. To give three examples : - Thermo stabilized papers - Aramide fibres (Nomex) for the turn insulation - Esters (MIDEL) as dielectric liquid. Nevertheless, their actual high cost still limits their practical use to low power rating apparatus for which the mass reduction associated with high operating temperatures is an important factor; the most usual application is the case of traction transformers. 3.
EVOLUTIONS AND NEW NEEDS
3.1. Sub-station Transformers on RTEâ&#x20AC;&#x2122;s Transmission Network The main evolutions for RTE result from a growing pressure on the transmission costs which leads to search for new technical and economic optimisation in the use of equipment. Therefore new operating modes, which go further than the existing practices, need to be defined for equipment without decreasing their reliability. As seen in § 1.1, the substation transformers are, most of the time, loaded under their nameplate rating but they also have to face overloads due to climatic events or to unavailabilities (N-1 situation). It is estimated that the thermal ageing of substation transformers does not exceed a few percent of a transformer ageing running continuously at full load. The limiting factor to decide for a reinforcement is then the hotspot temperature, which can be reached during these overloads. In the same way, to allow an access to the market of electricity to all the actors, it is necessary to be able to connect new producers in a short time as well as to facilitate the exchanges on the interconnections. These new elements require to bring fast answers to solve the local constraints on the network. Among the various solutions to relieve congestion zones with high load flows, one of them consists on taking profit of the existing margins on the network by installing s like phase-shifting transformers. One of the characteristics of the phase-shifting transformers compared to the substation transformers, is to be in series with transmission lines. Therefore their transmission capacities must be compatible with those of the line in steady state operation as well as in overload conditions. However these loading capacities are dependent on the temperature and the thermal behaviour of a line is very different from that of a transformer. Moreover the loading capacity of a line can be reinforced in future. These two examples illustrate the need to modify the operation rules of transformers. Several possibilities exist : to operate at continuous loads and overloads exceeding the nameplate rating by accepting an accelerated thermal ageing rate,
- to assess the margins on the design of the transformers, - to increase their performances (for example by improvement of the cooling system efficiency). The implementation of these solutions requires to be able to calculate accurately the temperature rise and to know the laws of thermal ageing. 3.2. Generator step-up transformers at EDFâ&#x20AC;&#x2122;s nuclear power stations With the operating conditions of these transformers and the life expectancy of power stations where they are installed, particular attention has begun to be focused to thermal ageing of the first-generation equipment, which is presently considered to be, on average, at mid life. In the event of a demonstrated generic thermal problem, a corrective action could be defined and applied to all the identical units. In case of failure, the equipment is no longer systematically replaced with the original design, but with newly design equipment, paying a particular attention to the thermal performances. Therefore, the new computing tools and the new measurement device enable the manufacturers to research thoroughly on the two following items : extending of life time of the first-generation equipment, with respect to original specifications, from 30 years to at least 40 years testing of thermal performances of new designs. An illustration of this second aspect is developed at § 4.2. 4.
DESIGN TOOLS AND THEIR VALIDATIONS
4.1. Examples of calculation tools fitted to new needs The design tools and their validations have been improved using new calculation means, applicable for any existing transformer technology. We can illustrate these progresses on a case study concerning a three phase substation transformer of 70 MVA 227/21 kV Yy 50 Hz. 4.1.1. Analytical methods New methods have been recently developed, from which we can notice a simple one for winding temperature rise calculation [3]. The general formulation of the problem uses the electrical analogy. From analytical tools, we calculate the thermal resistance of the solid insulation. The calculation of the thermal resistance of the oil boundary layer is determined using the correlation of test data from actual transformers, for natural or directed cooling. The major improvements of this new method are the following : the new method dispenses with the gross approximation that the heat transfer is uniform throughout the winding the treatment of the solid insulation is more rigorous test data from actual transformers is used to calculate the heat transfer coefficient of the oil boundary layer. This leads to more accurate results, as shown in Table I. Table I: Average and standard deviation errors measurements (in K) Layer Disc windings windings ON OD ON OD average
deviation
between calculations
average deviation average deviation
and
averag deviation e
between Previous 2.6 methods and 5.6 New -0.5 method
between 5.9 and 6.3 2.6
1.8
9.5
-0.5
3.7
between between -0.4 1.2 -4.4 and 3.5 and 2.2 -0.5
1.3
-2.5
3.5 2.2
For the example of three units of 70 MVA, differences between calculation with new method and measurements vary from â&#x20AC;&#x201C;0.9 to 1.1 K. 4.1.2. Finite-element methods
The example in Figure 4 shows the oil flow distribution calculated in a group of discs separated by two washers. Even if it is very difficult to get precise experimental validations of such models, these studies can be useful for parametric analyses which can improve, for example, the design of the oil ducts. Tools using finite-element methods are getting more and more powerful and give, today, possibilities of coupling loss, thermal and hydraulic distributions. But, if they are more and more advanced, their uses require more competencies. For example, oil volumes need to be modelled with sufficient number of meshes, which reduce today the use of these tools to certain parts of the transformer without being able to treat it as global. We can, for example, examine the oil flow distribution in winding bottom blocks (see Figure 3). This study can help to understand some oil distribution problems or to be a basis for shape optimisation.
From methods similar to the analytical ones (electrical analogy), it is possible to represent the transformer behaviour with a system of equations using a loss, thermal and hydraulic coupling. The whole transformer and its cooling devices can be modelled by some systems whose definitions and numbers of elements are chosen to have sufficient information. For example, we can get the temperature distribution within the windings, and more particularly the hot spot location and the mean copper temperature rises (see Figure 5 for the case study of the 70 MVA). This last information can be easily compared to the temperature rise test measurements and then validate the calculations. This comparison canmade for all windings and for all types of cooling modes (ONAN, ONAF, ODAF). This thermal hydraulic model can be also used for transient analyses, for example for future applications on overload capabilities. We can note that this transient ability can be validated by the temperature rise test measurements, in which a cooling curve is measured.
4.2. Example of instrumentation for a new design With the occasion of an order, a collaboration was established between the manufacturer and the user in order to equip the windings of a GSU transformer with thermal sensors. This was in order to enable the online reading of the winding temperature evolutions during the factory heat run test and later during operation on site. - Electrical characteristics of the transformer : The apparatus equipped is a single phase pole which is part of a three phase bank of
a 1400 MW nuclear plant step up transformers. These transformers are oil immersed and are of shell type. The main characteristics are as follows : Number of phases : 1 Power rating : 570 MVA Frequency
: 50 Hz
Number of windings : 2 Voltage rating : 20/405 kV+/-2.5 % Ynd Cooling : ODAF Arrangement of the windings of the transformer : The transformerâ&#x20AC;&#x2122;s windings are laid out symmetrically. In each half of the transformer, the HV winding is composed of two groups located on both sides of the LV winding. Electrically, the HV is composed of two sections in parallel ([coil1-7 + coil1625]//[coil26-35 + coil44-50]). The LV is composed of four sections in parallel ([coil811]//[coil12-15]//[coil36-39]//[coil40-43])]. [Figure 7] .
Determination of the points to be equipped and instrumentation The determination of the hottest spots of the coils is based on the manufacturerâ&#x20AC;&#x2122;s experience, taking into account the local distribution of losses in the coils, the number of heat transfer surfaces, the overheating due to insulated parts (presence of spacers), the average oil flow rate and the overheating due to reduced oil flow rates in some parts of the windings. The calculations made by the manufacturer were confirmed by a more detailed 2D thermo/hydraulic model performed by the R&D department of the Utility taking into account the local losses and also oil speeds between the spacers [Figure 9]. This modelling allowed to validate and to supplement the instrumentation locations initially defined by the manufacturer. Thus, during the design review dedicated partly to the thermal aspects, by mutual agreement, it was decided to place 10 optic fibres on the coils of the LV winding : - 4 optic fibres on coil number 8. - 4 optic fibres on coil number 43 (coil symmetrical of the 8) . - 1 optic fibre on coil number 13. - 1 optic fibre on coil number 15. - 2 other optic fibres in oil, in the vicinity of coils 8 and 43. The following Figure 8 and Figure 10 illustrate the implantation technique developed by the manufacturer and the optic fibre locations on coils 8 and 43.
The optic fibres used are point sensors, performing temperature measurements, thanks to a semi- conducting cristal in gallium arsenide (GaAs), using the principle of photoluminescence. This type of optic fibres was qualified by the transformer manufacturer, particularly regarding the dielectric, mechanical and thermal stresses. The instrumentation also comprises two measuring apparatus (transmitter, receiver, reading and information storage), giving access to 2x6 measurement channels. Thanks to positive feedback already acquired by the manufacturer on some other large power transformers in service, the optic fibres will be kept in the transformer for online measurements of windings temperature in service on line. - Measurement results during the factory heat run test : The factory heat run test was performed following the short-circuit method as described in the standards (IEC 60076-2). Below are the curves of evolution of the LV winding hottest spot temperature as well as the temperature of the surrounding oil during this test.
5.
CONCLUSIONS
After a presentation of specificities concerning loading of the generator step-up transformer on the one hand and the substation transformer on the other hand, this report has set out the new needs introduced by evolutions of the electricity market. These needs concern the ability of existing equipment to be used in different operation modes or the definition of spare unit supply based on new requirements. For the two transformers types, the new operating modes require the mastering of temperature rise calculation on the one hand and ageing rules on the other hand. At the same time the manufacturers have made progress in controlling the generation and the dissipation of the losses as well as using traditional or highertemperature materials. Thus they have developed new calculation tools based either
on simple analytical methods or using thermal modelling. By their increased know-how, the manufacturers are able to help the users to master the evolution of theirs new needs. Prepared By: zone4info.com Source: cigre 21, rue d'Artois, F-75008 Paris 6. REFERENCES [1 ] B.Favez, F.Salgues, H.Larrue, “EDF’s loading rules of power transformers for network interconnection and supply to the distribution network“, RGE, July-August 1969, Tome 78 n°7-8, pp.749-768 [ 2 ] A.TANGUY, I.HENNEBIQUE, J.POITTEVIN, J.SAMAT, “Direct fiberoptic hot-spot temperature measurement in an operating transformer“, CIGRE, Paris Session 1990, Report 12106 [3] S. A. Ryder, “A simple method for calculating winding temperature gradient in power transformers”, IEEE Transactions on Power Delivery, Vol. 17, No. 4, October 2002
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Zone4info - Understanding Percent Impedance
Understanding Percent Impedance Posted by Mark David July 14
Introduction: Drives use semiconductor devices for electrical power conversion. These devices are sensitive to power surges, voltage spikes, current surges, line distortion and power anomalies, all of which may have detrimental effects on semiconductor device operation. Line inductance reduces power surges. Inductive power circuit components such as reactors, inductors, chokes and transformers reduce rate of current change in the circuit and are used to “condition” power circuit. Inductance is often expressed in value of “percent impedance”
Definition: Percent Impedance or Percent IZ (%IZ) is the voltage drop due to impedance, at rated current, expressed in a percent of the rated voltage. Discussion: Baldor drives require certain line impedance for three important reasons: 1. Minimum inductance is necessary for proper commutation of semiconductor devices. 2. Line inductance reduces power sub-transient and transient surges. 3. Impedance reduces available short circuit current in case of malfunction. Drives Installation and Operation Manuals list necessary minimum impedance and short circuit ratings. What do these impedance percentages really mean? As stated in the above definition, percent impedance is always expressed at rated base current. It is very important to understand that recommended percent impedance is based on drive full load current rating and not the reactor, transformer, or other device current rating. Here are few examples: A. 10HP, 460V, 14A, Baldor VS1SP410-1B inverter drive requires 1% impedance and is rated for 5kA short circuit current. That means that line voltage drop at current level at 14A should be at 4.6V B. 10HP, 460V, 18A, Baldor line reactor LRAC01802 with 3 % impedance will have 13.8V voltage drop when conducting 18A. C. 100kVA, 460V, 125A, power distribution transformer with 5% impedance and serving several drives will have 5% or 23V drop at full load of 125A. Calculating line impedance
The purpose of these examples is to illustrate the importance that percent impedance in drives application must be evaluated on drive current rating base. Lets us further examine the above examples. Let us assume that the 10HP, 460V, 14A drive above is the only load on this 100kVA transformer. How much will voltage drop on the transformer when transformer is loaded only with 14A of driveâ&#x20AC;&#x2122;s current? In order to calculate this drop we use the simple ratio formula. If 125A drops 23V, then 14A will drop 14A/125A*23V or 2.6V. This value 2.6V is less then recommended drive input line impedance voltage drop of 4.6V. The conclusion is that 5% impedance 100kVA transformer does not meet the requirement of 1% impedance for 10HP drive. Evaluating short circuit impedance Power source impedance is also and easy way to evaluate available short circuit rating. In the above example, we have discussed the VS1, 10HP, 460V drive which has listed short circuit rating of 5,000A symmetrical RMS (root means square) current. Let us conduct and a simple short circuit study. Let us assume that 100kVA transformer has unlimited power available from the utility on the primary side (which is mostly a case in short circuit studies) and let us assume that there are no rotating motors on this power system to contribute to short circuit level (which is not a case in most short studies). In this circuit with the assumptions made, the phase to phase of short circuit in the drive, at the simplest calculation will be full load current divided by percent impedance or 125A/.05=2500A. The available short circuit current is less then drive listed short circuit rating. There is no reason for concern. Now let us look at 200kVA, 250A, transformer with 4% impedance. Short circuit current on the drive feed from this transformer would be 6.3kA, more then drive short circuit rating. Installing this 10HP drive on 200kVA transformer possibly compromises drive short circuit rating and increases the possibility of drive failure. Source: Baldor Drives
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Zone4info - Substation Automation
Substation Automation Posted by Ashok Kumar July 12
Substation Automation (SA) can provide integral functions to the distribution grid automation. As more IED devices are installed to the distribution network, the need for IED management , control, and the corresponding advanced application operation is a growing imperative. Moreover, the Smart Grid applications, such as the Integrated Voltage and Var Control (IVVC), Fault Detection Isolation and Restoration (FDIR) in Distribution Automation (DA), and Advanced Metering Infrastructure (AMI), as well as the Demand Response (DR), offer increased operational functionality for distribution substation and feeders. To realize the full benefits of these new applications, a well designed substation automation architecture will provide scaled approach for adding new automation functions, take use of shared communication infrastructure for feeder automation and AMI, and offer provision for updates to the network model. Traditionally, SA has been focused on automation functions such as monitoring, controlling, and collecting data inside the substation. This narrow scope allows for effective control of automatic devices located within the substation fence, but does not fully take advantage of automated feeder devices. With the arrival of the Smart Grid comes a new level of expectation for distribution automation. Substation Automation is expected to expand dramatically with increased control of relays, capacitor banks, and voltage regulators along the feeders. New applications are expected to incorporate distributed energy resources, AMI and DR functions. This paper discusses the approach to distribution SA incorporating DA, DR and AMI. 1. Overview of Conventional SA Conventional SA systems are often viewed separately from the protection and control functions within a substation. Although it is deemed important , the SA infrastructure is often considered in isolation for automation purposes. In North America the transmission substations have often been automated by the installation of Remote Terminal Units (RTUâ&#x20AC;&#x2122;s), connected to a central EMS /SCADA system, with hard wired I/O in the substation and very little automation applications running in the substation to make it more autonomous during adverse conditions. Distribution substations were rarely connected to a central SCADA system, and were not important enough in the scheme of things to be automated. Even utilities that have done Feeder Automation (FA) as part of their DA system have often neglected to automate the distribution substations. Some utilities have started in the past few years to collect data from protection relays where numerical relays were installed and brought that to the central SCADA for visualization and remote control. In the rest of the world, specifically the IEC world, fully integrated SA systems with several smart applications for increased intelligence in the substations have been
developed. In addition, until very recently, the security based on the User Name and Password in SA and other automation systems has been viewed as quite sufficient . Even the different levels of access that can be achieved with this level of protection have not been fully utilized with sharing of log-in information between engineers, technicians and other network operation people in the order of the day. That situation has changed very drastically in the last couple of years with the NERC-CIP dictating amore rigorous review of security requirements and implementation of a proper physical and Cyber security system for critical assets in the electrical infrastructure Upon further evaluation of effective global smart grid architecture, it is clear that the substation should play an expanded role in the ‘smartness’ of the grid than in the past . The substation has always been important to the operation of the grid, the SA system now can play the same type of role in the intelligence and become the nerve center of the Smart Grid. For this to happen, standards are urgently required, the looseness that was there in the market in the past with utilities drafting their own standards loosely based on regional (IEEE) or global (IEC) standards has to stop in order to embrace the true benefits. A larger acceptance of global standards will also allow the manufacturers of automation equipment the ability to concentrate on the real issues in providing equipment (IED’s, Networking equipment , Software applications) and solutions that will enhance the reliability and improve the efficiency of the electrical network. Adoption of standardization in communication protocol and systems e.g. IEC 61850 will be able to focus the R&D money to find advantages in areas of intelligence of the networks to provide a true Smart Grid. The three main groups of components to achieve this goal are: 1) Smart IED’s for sensing, measuring and control of network parameters and equipment 2) Interoperable communications networks to tie the different pieces together 3) Software applications at various levels of the network including the Substation system that can manage the other pieces of the automation system In this new architecture the SA system can be seen as a decentralized nerve center, enabling the network to be more efficient and more reliable locally while still connected to a higher level of intelligence with a wider perspective, e.g. SCDA/EMS/ DMS systems. By keeping the local decision on these aspects local, with substation and feeder automation equipment working in concert , the higher level systems and the communication infrastructure connecting them are freed up to make the higher level determinations for optimization to achieve the eventual goals of improving the network operation, reduce the losses and the impacts that energy transmission and distribution have on the environment . The SA functions can introduce considerable benefits to the utilities as follows: Operational Interoperability, distributed intelligence, integrated communications and systems for greater efficiency and reliability of the equipment , network and energy supply. Financial Reduced losses have direct financial benefits. Each KWH that does not have to be generated or transmitted directly reduces the cost of supply. Utilizing the networks more efficiently allow a longer life of equipment and an increased throughput of useful energy, allowing the utility to delay network upgrades. Using the intelligence in the network applications and automation the systems in the substation peak loads can be manipulated and reduced. This reduction has direct benefits for reduced purchase of the more expensive peaking power Upon further evaluation of effective global smart grid architecture, it is clear that the substation should play an expanded role in the ‘smartness’ of the grid than in the past . The substation has always been important to the operation of the grid, the SA system now can play the same type of role in the intelligence and become the nerve center of the Smart Grid. For this to happen, standards are urgently required, the looseness that was there in the market in the
past with utilities drafting their own standards loosely based on regional (IEEE) or global (IEC) standards has to stop in order to embrace the true benefits. A larger acceptance of global standards will also allow the manufacturers of automation equipment the ability to concentrate on the real issues in providing equipment (IED’s, Networking equipment , Software applications) and solutions that will enhance the reliability and improve the efficiency of the electrical network. Adoption of standardization in communication protocol and systems e.g. IEC 61850 will be able to focus the R&D money to find advantages in areas of intelligence of the networks to provide a true Smart Grid. The three main groups of components to achieve this goal are: 1) Smart IED’s for sensing, measuring and control of network parameters and equipment 2) Interoperable communications networks to tie the different pieces together 3) Software applications at various levels of the network including the Substation system that can manage the other pieces of the automation system In this new architecture the SA system can be seen as a decentralized nerve center, enabling the network to be more efficient and more reliable locally while still connected to a higher level of intelligence with a wider perspective, e.g. SCDA/EMS/ DMS systems. By keeping the local decision on these aspects local, with substation and feeder automation equipment working in concert , the higher level systems and the communication infrastructure connecting them are freed up to make the higher level determinations for optimization to achieve the eventual goals of improving the network operation, reduce the losses and the impacts that energy transmission and distribution have on the environment . The SA functions can introduce considerable benefits to the utilities as follows: Operational Interoperability, distributed intelligence, integrated communications and systems for greater efficiency and reliability of the equipment , network and energy supply. from less efficient power plants, thereby reducing the utilities cost of operations. Non-Financial Non-Financial benefits of the improved substation and feeder automation systems are: • Reduction of Green House Gas Emissions • Improved customer satisfaction through higher reliability and reduced outages. • More efficient utilization of scarce highly skilled resources • Coordinated training courses and material to increase the pool of resources available to the industry. Applications of DA, DR and AMI in SA In the extended SA systems, some of the advanced applications in DA, DR and AMI can be incorporated/implemented for enhanced operation performance and capability. DA Applications – IVVC, FDIR Refer to Appendix 1. The net result is that directional relaying is only required where the DG is large enough to trip the devices on an adjacent feeder for faults on that feeder. Tripping devices on the same feeder has no impact on reliability. DA is not only a key module in distribution grid operation but also a hub connecting other important modules and applications in Smart Grid, such as the Demand Response Management System (DRMS), Advanced Metering Infrastructure (AMI) and Outage Management System (OMS). In general, a DA system comprises of various advanced applications, such as Topology Processor (TP), Distribution Power Flow (DPF), Fault Detection, Isolation and Restoration (FDIR), Integrated Voltage/Var Control (IVVC), Optimal Feeder Reconfiguration (OFR), Distribution Contingency Analysis (DCA), Distribution State Estimation (DSE), Distribution Load Forecasting and Estimation (DLF/DLE), etc. Among them, FDIR and IVVC are the key applications in real time operation and, therefore, are considered as the typical DA applications in the distributed approach while being incorporated into the SA solution.
IVVC is designed for improved distribution system operation efficiency, offering the following basic objectives: 1) Reducing feeder network losses by controlling the feeder capacitor banksâ&#x20AC;&#x2122; on/off status 2) Maintaining healthy voltage profile in normal operation condition 3) Reducing peak load through feeder voltage regulation by controlling the transformer tap positions in substations and voltage regulators in feeder sections. IVVC optimally coordinates the controls of capacitor banks, voltage regulators and transformer tap positions installed at the feeder circuits and substations. Because the Var output of a capacitor bank is tightly coupled with the voltage in nature, a control action on a capacitor bank for adjusted Var output or on a voltage regulator for a different voltage level can result in significant impacts to each other. Advanced optimization algorithms are necessary for coordinated controls in IVVC for optimal benefits to both healthy voltage profile and feeder efficiency. On the other hand, FDIR is designed to improve the distribution system reliability by detecting faults occurred at feeder sections based on the remote measurements from the feeder RTUs (i.e., FTUs), quickly isolating the fault by opening the adjacent switches and then restoring the service for the healthy sections affected by the fault . It can reduce the service restoration time from several hours down to 30 seconds or less, considerably improving the distribution system reliability and service quality in terms of the distribution reliability indices of CAIDI, SAIFI SAIDI, etc. In addition to FDIR and IVVC, the topology processing function of TP plays an important role in supporting the two key applications in real time operation. TP is a background processor that traces the distribution network to track the topology connectivity for internal data processing for the applications and display colorization. TP can also provide service for intelligent alarm processing to suppress unnecessary alarms associated to topology changes. Another key application in DA is DPF, which is the core function of almost every DA application, especially for FDIR and IVVC. It is designed to solve the three phase unbalanced load flow for either meshed and radial operation scenarios of the distribution network for evaluation or analytic purposes. Conventionally, SA is defined as the automation system inside the substation fence, completely isolated from the DA functions. In Smart Grid, however, the conventional SA system can be effectively expanded to incorporating DA functions by including the feeder automation functions in the region served by the substation. This expands the service territory of the conventional SA to the area of the feeder circuits in its service territory, effectively combining the SA with the FA functions in a distributed manner. DR - Aggregation and Disaggregation Demand Response is relatively a new function in Smart Grid. It is designed to directly manage the individual customer loads with two-way communication. The potentially dispatchable portion of the individual loads can be aggregated to participate in the system wide economic dispatch for reduced peak demand and minimum energy cost . On the other hand, the dispatched amount of load management can be distributed to the individual loads through disaggregation. The processes of aggregation and disaggregation require an effective coordination with the DA system for optimal grid operation subject to the constraints on voltage and loading limits. The similar process is needed in the recovery stage while returning to the normal operations for the individual customers. The DA functions in SA can also be designed to play the role properly, similar to the centralized DMS system. AMI â&#x20AC;&#x201C; End of line Measurements
AMI system is receiving more and more attention in the context of the Smart Grid. In addition to the conventional roles in accounting and customer billing, the AMI data from the individual customers can also be used to enhance the distribution system operation and management , including the historical load profiles for more accurate load forecasting and estimation, as well as the real time information at the end points of feeders to feed DA functions.
Conventionally, the service territory of a SA is limited to inside the substation fence. While extending the automation scope to include the feeders served by the substation, the service scope of SA is expanded to the distribution feeder circuits. Because the feeders may have open ties to other feeders that are served by other substations, the DA system in a substation has to have the capability to support interoperability with the neighboring substations, becoming the real challenge to the distributed DA systems in SA As described previously, the integration of DA, DR and AMI through data and information exchange can effectively enhance the operation performance of the distribution systems. This advantage can apply to the distributed DA systems too. However, a distributed DA system in a SA can only cover the pre-configured feeders for the substation, a small part of the entire distribution network. The entire distribution network may involve many distributed DA systems in SAs, each covering one or more substations (a logical or virtual substation). In order to implement the automation for a partial or the entire distribution system with the distributed DA systems, an advanced self- coordinating mechanism is required for the individual DA systems to work properly in a well coordinated way through peer-to-peer communications, as schematically shown in Figure
The service area of a distributed DA system can include one or more substations. Each area is a part of the connected distribution network that connects to the neighboring areas through the normal open tie-switches. The node at each end of the tie-switch belongs to the area it resides, setting up the boundary of the area. The DA function in each area is fully responsible for the operation of the area. Both parties will exchange or share the boundary information. Figure 2 and Figure 3 illustrate the typical coordination between two areas for FDIR and IVVC operations. It can be seen from Figure 2 that when a fault is detected by the DA system in Substation A, the FDIR logic isolates the faulted section, restores the service of the upstream sections immediately, then calculates the total load of the downstream sections and checks the loading and voltage limits to figure out the minimum capacity and voltage requirements for substation B to pick up. If substation B is not capable to pick up the load for restoration, alternative approaches will be evaluated, including using multiple sources, transferring loads from one feeder to another in substation B to make more spare capacity, or executing partial restoration to restore service to as much load as possible.
Summary Conventionally, SA has been focused on automation functions such as monitoring, controlling, and collecting data inside the substation. This is a narrow scope to allow for effective control of automatic devices located within the substation fence, but cannot well take advantage of automated feeder devices. In Smart Grid, the SA system in distribution substations can be extended to include the automated feeder devices distribution circuits supplied by the substation. The SA functions in distribution substations can include the key DA functions, such as IVVC and FDIR and can incorporate the AMI and DR data for further enhanced operation performance. An overall review of the conventional SA functions is presented and the extended SA functions in distribution substations are discussed with DA, AMI and DR functions incorporated in Smart Grid operation. Source: Jiyuan Fan, Willem du Toit , Paul Backscheider GE Digital Energy Reference [1] Jiyuan Fan, Xiaoling Zhang, “Feeder Automation within the Scope of Substation”, Proceedings of Power Systems Conference and Exposition, 2006 PSCE ’06. 2006 IEEE PES, Atlanta, GA, ISBN: 1-4244-0177-1’, pp 607 - 612
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Zone4info - Wire Sizes and Maximum Length Determination
Wire Sizes and Maximum Length Determination Posted by Zeshan Rajput July 7
Wire Sizes and Maximum Length Determination Wire sizes become important at low voltages. At 12 volts DC a loss of more than 10% in voltage across the length of the wire can mean the difference between the inverter
running or not running. The currents can get high and any voltage drop becomes significant. In general at 12 Volts DC one should run the inverter close to the battery and then pipe the 120 Volts AC to the point of use on smaller wire. The general rule is at low voltages pay attention to voltage drop and at high voltages pay attention to maximum current caring capacity for the size of wire. Properly sized wire can make the difference between inadequate and full charging of a battery system, between dim and bright lights, and between feeble and full performance of tools and appliances. Designers of low voltage power circuits are often unaware of the implications of voltage drop and wire size. In conventional home electrical systems (120/240 volts ac), wire is sized primarily for safe amperage carrying capacity (ampacity). The overriding concern is fire safety. In low voltage systems (12, 24, 48VDC) the overriding concern is power loss. Wire must not be sized merely for the ampacity, because there is less tolerance for voltage drop (except for very short runs). For example, a 1V drop from 12V causes 10 times the power loss of 1V drop from 120V. Use the following charts as your primary tool in solving wire sizing problems. Determining tolerable voltage drop for various electrical loads A general rule is to size the wire for approximately 2 or 3% drop at typical load. When that turns out to be very expensive, consider some of the following advice. Different electrical circuits have different tolerances for voltage drop.
DC TO AC INVERTERS: Plan for 3 to 5% voltage drop. In a push to shove situation one can use up to a 10% voltage drop as a maximum. LIGHTING CIRCUITS, INCANDESCENT AND QUARTZ HALOGEN (QH): Don't cheat on these! A 5% voltage drop causes an approximate 10% loss in light output. This is because the bulb not only receives less power, but the cooler filament drops from white-hot towards red-hot, emitting much less visible light. LIGHTING CIRCUITS, FLUORESCENT: Voltage drop causes a nearly proportional drop in light output. A 10% drop in voltage is usually the max. Fluorescents use 1/2 to 1/3 the current of incandescent or QH bulbs for the same light output, so they can use smaller wire DC MOTORS operate at 10-50% higher efficiencies than AC motors, and eliminate the costs and losses associated with inverters. DC motors do NOT have excessive power surge demands when starting, unlike AC induction motors. Voltage drop during the starting surge simply results in a "soft start". AC INDUCTION MOTORS are commonly found in large power tools, appliances and well pumps. They exhibit very high surge demands when starting. Significant voltage drop in these circuits may cause failure to start and possible motor damage. Follow the National Electrical Code. In the case of a well pump, follow the manufacturer's instructions. MOST CHARGING CIRCUITS are critical because voltage drop can cause a disproportionate loss of charge current. To charge a battery, a generating device must apply a higher voltage than already exists within the battery. A voltage drop greater than 5% will reduce this necessary voltage difference, and can reduce charge current to the battery by a much greater percentage. WIND GENERATOR CIRCUITS: At most locations, a wind generator produces its full rated current only during occasional windstorms or gusts. If wire sized for low loss is large and very expensive, you may consider sizing for a voltage drop as high as 10% at the rated current. That loss will only occur occasionally, when energy is most abundant. Consult the wind system's instruction manual. ALUMINUM WIRE may be more economical than copper for some main lines. Power companies use it because it is cheaper than copper and lighter in weight, even though a larger size must be used. It is safe when installed to code with AL-rated terminals. You may wish to consider it for long, expensive runs of #2 or larger. The cost difference fluctuates with the metals market. It is stiff and hard to bend, and not rated for submersible pumps.
Amperage (Operating Current Maximum) Volt 2% Wire Loss Chart Maximum distance one-way in feet of various gauge two conductor copper wire from
2% Voltage Drop Chart Amps 1 2 4 6 8 10 15 20 25 30 40 50 100 150
#14 45 22.5 10 7.5 5.5 4.5 3 2 1.8 1.5 . . . .
#12 70 35 17.5 12 8.5 7 4.5 3.5 2.8 2.4 . . . .
#10 115 57.5 27.5 17.5 13.5 11 7 5.5 4.5 3.5 2.8 2.3 . .
#8 180 90 45 30 22.5 18 12 9 7 6 4.5 3.6 . .
#6 290 145 72.5 47.5 35.5 28.5 19 14.5 11.5 9.5 7 5.5 2.9 .
#4 456 228 114 75 57 45.5 30 22.5 18 15 11.5 9 4.6 .
#2 720 360 180 120 90 72.5 48 36 29 24 18 14.5 7.2 4.8
#1/0 . 580 290 193 145 115 76.5 57.5 46 38.5 29 23 11.5 7.7
#2/0 . 720 360 243 180 145 96 72.5 58 48.5 36 29 14.5 9.7
#4/0 . 1060 580 380 290 230 150 116 92 77 56 46 23 15
power source to load for 2% voltage drop in a 12 volt system. You can go twice the distance where a 4% loss is acceptable. A 4 to 5% loss is acceptable between batteries and lighting circuits in most cases. Multiply distances by 2 for 24 volts and by 4 for 48 volts. Maximum Ampacities (Amperage Capacity) for Wire Maximum Ampacity for Copper and Aluminum Wire Copper
Wire Size 167° F (75° C) *14 *12 *10 8 6 4 2 1 1/0 2/0 3/0 4/0
Aluminum
194° F (90° C) 167° F (75° C) 20 25 35 50 65 85 115 130 150 175 200 230
25 30 40 55 75 95 130 150 170 195 225 260
194° F (90° C) 20 30 40 50 65 90 100 120 135 155 180
. 25 35 45 60 75 100 115 135 150 175 205
Allowable ampacities of conductors (wires) in conduit, raceway, cable or directly buried, based on ambient temperature of 86° F (30° C). NEC allows rounding up cable ampacity to the next size standard fuse or breaker. Use this table for high voltages of 120 volts or higher.
Quick Overview As electric current flows through wire, there is a loss in voltage. This loss is referred
to as IR voltage drop. Voltage (Drop) = Wire Resistance Times Amps of current (E=IR) Calculating the voltage loss for a pair of wires gets a little complicated, so we have constructed a quick look up table for what size wire you will need for your application. The table below is for 12-volt ac or dc devices only. You just need to know the power in Watts (VA), or Amps and the table will show how far you can go in feet for any size wire pair listed. The table is based on a 10% loss of voltage on a pair of wires. This should work for most 12-volt devices. Checking the manufacturerâ&#x20AC;&#x2122;s specifications, use the maximum watts or current and be sure the minimum operational voltage is 10v or below. The footage in the table is linear, a 20% loss would double the distance, or 5% would cut it in half. The table calculations are based on the ohms of the wire at 70oF. If the wire temperature is raised to 130oF the voltage drop would increase by about 3%. The voltage drop calculations are also based on a conventional load. The recommended maximum distances in feet for AC or DC are listed in the cell below the wire size. 12V TABLE POWER W(VA)/Amps 8awg 10awg 12awg 14awg 26awg 3W/.25A 4W/.33A
WIRE GAUGE 16awg 18awg 20awg 22awg 24awg
3,733 2,396 1,508 947 595 376 234 146 93 2,828 1,815 1,142 717 451 285 177 111 70
12V TABLE POWER W(VA)/Amps 8awg 10awg 12awg 14awg 26awg 3W/.25A 3,733 2,396 1,508 947 595 4W/.33A 2,828 1,815 1,142 717 451 5W/.42A 2,222 1,426 898 564 10W/.83A 1,124 722 454 285 20W/1.67A 559 359 226 142 30W/2.50A 373 240 151 95 40W/3.33A 280 180 113 71 50W/4.17A 224 144 90 57 60W/5.00A 187 120 75 47 70W/5.83A 160 103 65 41 80W/6.67A 140 90 57 35 90W/7.50A 124 80 50 32 100W/8.33A 112 72 45 28 110W/9.17A 102 65 41 26 120W/10.00A93 60 38 24 12 Volts â&#x20AC;&#x201C; Wire Sizes (Gauge) 3 % Drop for Radios
59 44
WIRE GAUGE 16awg 18awg 20awg 22awg 24awg
376 234 146 93 285 177 111 70 354 224 139 179 113 71 89 56 35 60 38 23 45 28 18 36 23 14 30 19 12 26 16 10 22 14 N/A 20 13 N/A 18 11 N/A 16 10 N/A 15 N/A N/A
59 44 87 44 22 15 11 N/A N/A N/A N/A N/A N/A N/A N/A
55 28 14 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A
35 18 9 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A
Total Wire Length in Feet 10 15 20 25 30 40 50 60 70 80 90 100
5
Amp 10
18 16 14 12 12 10 10 10 8
14 12 10 10 10 8
6
6
6
6
8
8
4
4
6
15 20 25 30 40 50 60 70 80 90 100
12 10 10 10 8 6 6 6 6 4 4
10 10 8 8 6 6 4 4 4 2 2
10 8 6 6 6 4 4 2 2 2 2
8 6 6 6 4 4 2 2 2 1 1
8 6 6 4 4 2 2 1 1 0 0
6 6 4 4 2 2 1 0 0 2/0 2/0
6 4 4 2 2 1 0 2/0 3/0 3/0 3/0
6 4 2 2 1 0 2/0 3/0 3/0 4/0 4/0
4 2 2 1 0 2/0 3/0 3/0 4/0 4/0
4 2 2 1 0 2/0 3/0 4/0 4/0
2 2 1 0 2/0 3/0 4/0 4/0
2 2 1 0 2/0 3/0 4/0
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Zone4info - Principle of transformer action
Principle of transformer action Posted by Zeshan Rajput July 6
Principle of transformer action
A current flowing through a coil produces a magnetic field around the coil. The magnetic field strength H, required to produce a magnetic field of flux density B, is proportional to the current flowing in the coil. Figure 2.1 shown below explains the above principle
Relationship between current, magnetic field strength and flux The above principle is used in all transformers. A transformer is a static piece of apparatus used for transferring power from one circuit to another at a different voltage, but without change in frequency. It can raise or
lower the voltage with a corresponding decrease or increase of current.
Figure 2-2: Transformer schematic When a changing voltage is applied to the primary winding, the back e.m.fs generated by the primary is given by Faradayâ&#x20AC;&#x2122;s law,
A Current in the primary winding produces a magnetic field in the core. The magnetic field is almost totally confined in the iron core and couples around through the secondary coil. The induced voltage in the secondary winding is also given by Faradayâ&#x20AC;&#x2122;s law A 50 Hz transformer with 1000 turns on primary and 100 turns on secondary, maximum flux density of 1.5 Tesla and core area of 0.01 m2. J is taken as 2 Amps/Sq. mm and A cons as 30 mm2 for this illustration. Voltage developed is given by In primary winding, Eprimary = 4.44 X 50 X 1000 X 1.5 X 0.01 = 3330 Volts
= 4.44 x f x Np x Bmax x Acore,
In secondary winding Esecondary = 4.44 x f x Ns x Bmax x Acore, = 4.44 X 50 X 100 X 1.5 X 0.01 = 333 Volts Volt-ampere capability is given by the following relationship: Power rating = 4.44 x f x Np x Bmax x Acore x J x Acond, X 0.001 KVA. = 4.44 X 50 X 1000 X 1.5 X 0.01 X 2 X 30 X 0.001 = 200 kVA approximately. Actual Rated KVA = Rated Voltage X Rated Current X 10-3 for single phase transformers. Rated KVA = V-3 X Rated Line Voltage X Rated Line Current X 10-3 for three phase transformers. Prepared by: Zone4info.com Source: Indian Renewable Energy Development Agency,
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Zone4info - The Basics Of Selecting Overload Relays
The Basics Of Selecting Overload Relays Posted by Johan column June 30
Overload relays are inexpensive, but the results of selecting the wrong one for the application can be catastrophic for your motor, process, or both. When it comes to manufacturing, motors make the world go 'round. This makes proper motor protection mission-critical. Enter, the overload relay. Overload relays protect a motor by sensing the current going to the motor. Many of these use small heaters, often bi-metallic elements that bend when warmed by current to the motor. When current is too high for too long, heaters open the relay contacts carrying current to the coil of the contactor. When the contacts open, the contactor coil de-energizes, which results in an interruption of the main power to the motor. These contacts do not affect control power (which is often 120V), so don't assume an absence of potentially lethal current without a proper lockout/tagout. Types of relays. Overload relays and their heaters belong to one of three classes, depending on the time it takes for them to respond to an overload in the motor. The overload relay itself will have markings to indicate which class it belongs to. These include Class 10, 20, and 30. The class number indicates the response time (in seconds). An unmarked overload relay is always Class 20. Typical NEMA-rated overload relays are Class 20, but you can adjust many of them about 15% above or below their normal trip current. IEC relays are usually Class 10, and you can usually adjust them to 50% above their normal trip current. When replacing overload heaters, always replace the entire set. Why? Because there is some damage to the remaining two heaters, and you may wind up playing a game of musical chairs as they take turns failing prematurely. Heater selection. Selection is straightforward, if you can use the identical brand and size. However, this is not always possible. If you must select a different heater, refer to the manufacturer's selection tables. Your choice will depend on the full load amperage (FLA) of the motor, and the motor starter you use. For example, suppose you have to select replacement overloads for a 100-hp motor drawing 162A at full load. Let's say you have a NEMA Size 5 controller. We'll use an excerpt from an actual manufacturer's index of tables (see table, above). This example shows you how the selection criteria interact. All manufacturers' indexes and tables are easy to use, but let's do a dry run with this example. To make the proper selection from this manufacturer, start with the bulletin number (left column). This leads you to the proper table (right column). In this case, the index tells you to use Table Number 147 for the 506 Series A. On the manufacturer'sTable 147, you should locate the FLA of the motor in the column for NEMA Size 5 controllers. If the FLA of your motor does not exactly match the FLA of the table, just choose the closest heater element: W38 in this case. This assumes your motor and controller operate at the same temperature. If there is a small temperature difference (less than 15 degrees F) between the motor and the controller, choose a heater based on the controller. Choose the higher heater number if the controller is warmer than the motor. Choose the lower heater number if the controller is cooler than the motor. If there is a significant temperature difference (15 degrees F or more) between the motor and the controller, consult the manufacturer or supplier. Reliable overload protection for the motor will require further adjustments to the selection process. Editor's note: Don't confuse motor overload protection with circuit breaker protection, because they serve two different purposes. Your motor overload protection will interrupt power to the motor to protect only the motor. Your circuit breaker will open to protect the power distribution to the motor. You must do both, and no single device accomplishes both. You should size your circuit protection to protect the feeders, and coordinate the motor feeder circuit protection with the upstream breaker scheme. â&#x20AC;&#x201D;M.L.L.
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Zone4info - CT Sizing & Max Fault Level of Generator
CT Sizing & Max Fault Level of Generator Posted by Johan column June 26
CT Sizing & Max Fault Level of Generator Diesel Generating set comprises of diesel engine as the prime mover. When a short circuit occurs on the system powered by a generator, the generator continues to produce voltage at the generator terminals as the field excitation is maintained and the prime mover drives the generator at normal speed. The generated voltage causes a large magnitude fault current flow from the generator to the short circuit. The flow of fault current is limited only by the generator impedance and the impedance of circuit between the generator and short circuit. In case of a short circuit at the generator terminals, the fault current is limited by generator impedance only To calculate the fault current of the generator Generator Rating – 2000KVA Rated Voltage -415V Sub Transient Reactance Xd “ - 0.11 ( Reference Technical Data Sheet of Alternator ) Fault Current If = Fault MVA / √3 x kV Fault MVA = MVA / Xd” Fault MVA = 2/0.11 = 18.1818 Fault Current = 18.1818/ √3 x 0.415 = 25.295 kA Full Load Current of the Generator = MVA / √3 x kV =2.782kA or 2782 A This means that the fault current is 9times the full load current .
(25.295/2782 ) times i.e approximately
Due to this reason Class 5P10 CTs will suffice for Protection , as they will not saturate for upto 10times the rated current . Further Calculations Let us calculate the Knee Point Voltage requirement of CT for differential protection . The following assumptions are made during such a calculation for stability under worst external fault .The settings are such that the relay shall not operate for a spill current due to CT saturation under worst external fault conditions Consider a case where fault occurs outside the protected zone (i.e-external fault) . If= Fault Current RL= Lead Resistance RCT = CT Secondary resistance Vs= Voltage across the relay at the time of fault If
Vs = If (RCT + 2RL) Ifp = 25.295 kA (Primary Fault Current ) RCT = 0.582 ohms RL =0.11ohms ( Considering Length between AMF panel to DG as 15metres ) If = (Ifp*5)/3200
=39.52A
Vs= 39.52(0.582+0.22)= 31.69V Voltage across the relay during worst fault = Vs =31.69V Vk = Knee point Voltage of CT. Knee Point voltage of CT should be higher than this voltage across the relay Let us calculate the knee point volatge of the CT under consideration (Class 5P10) Vk = (VA x ALF ) / CT secondary + (CT secondary x ALF x RCT @ 75deg C) ALF = 10 RCT @75deg C = RCT X 1.15 Vk = (15 x 10) / 5
+
(5 x 10 x 0.582X1.15 ) = 30 + 33.465 = 63.465 V
Conclusion â&#x20AC;&#x201C; The knee point Voltage Vk of the Class PS CT is much higher than the voltage across the relay Vs for a worst external fault .Therefore Class 5P10 CT will suffice as it will not saturate under this condition . Source: Internet
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Zone4info - Speed Droop and Power Generation
Speed Droop and Power Generation Posted by Brown John June 18
Droop Engine Control for Stable Operation Speed droop is a governor function which reduces the governor reference speed as fuel position (load) increases. All engine controls use the principle of droop to provide stable operation. The simpler mechanical governors have the droop function built into the control system, and it cannot be changed. More complex hydraulic governors can include temporary droop, returning the speed setting to its original place after the engine has recovered from a change in fuel position. This temporary droop is called compensation. The ability to return to the original speed after a change in load is called isochronous speed control. All electronic controls have circuits which effectively provide a form of temporary droop by adjusting the amount of actuator position change according to how much off speed is sensed. Without some form of droop, engine-speed regulation would always be unstable. A load increase would cause the engine to slow down. The governor would respond by increasing the fuel position until the reference speed was attained. However, the combined properties of inertia and power lag would cause the speed to recover to a level greater than the reference. The governor would reduce fuel and the off speed would then occur in the underspeed direction. In most instances the off-speed conditions would build until the unit went out
on overspeed. With droop, the governor speed setting moves toward the offspeed as the fuel control moves to increase, allowing a stable return to steady state control. The feedback in the governor is from the output position. Since a minimal movement of the output position can cause major speed changes in an unloaded engine, it is sometimes difficult to gain stability in unloaded conditions. Actuator linkage requiring more movement of the output to achieve a given amount of rack movement at the idle settings than at the loaded settings will often help achieve stability in the unloaded position. Setting a greater amount of droop in the governor is another solution. In the case of isochronous (temporary droop) control, the governor speed with which the engine returns to the predetermined speed reference is adjustable, allowing greater flexibility in achieving stable operation, even when unloaded. The Droop Curve Droop is a straight-line function, with a certain speed reference for every fuel position. Normally, a droop governor lowers the speed reference from 3 to 5 percent of the reference speed over the full range of the governor output. Thus a 3% droop governor with a reference speed of 1854 rpm at no fuel would have a reference speed of 1800 rpm at max fuel (61.8 Hz at no fuel and 60 Hz at max fuel). (Notice that the feedback is over the full output-shaft rotation or fuel rod retraction of the governor. If only a portion of the output is used, the amount of droop will be reduced by the same proportion. Likewise the same governor would only have a droop from 1827 to 1800 if half of the full output moved the fuel rack from no fuel to full fuel (60.9 Hz droop to 60 Hz; probably not enough droop to provide stability). Figure 1 illustrates 3% and 5% droop governor speed curves, assuming the use of all of the servo movement. The speed figures given are theoretical since servo position and rack position are seldom absolutely linear. Most complex hydraulic governors have adjustable droop. In these cases, droop may be set between 0% and 5%. Droop is not adjustable in most mechanical governors, although some mechanical governors have provisions for changes in springs which will change the amount of droop. Five percent droop is common in simple mechanical governors, although 3% and 10% droop is not uncommon. Electric Generation A single engine electrical generator can operate in isochronous, changing speeds only temporarily in response to changes in load. This system can also operate in droop, if a lower speed is permissible under loaded conditions (see
Parallel with a Utility If, however, the single engine generator is connected to a utility bus, the utility will determine the frequency of the alternator. Should the governor speed reference be less than the utility frequency, power in the utility bus will flow to the alternator and motor the unit. If the governor speed is even fractionally higher than the frequency of the utility, the governor will go to full load in an attempt to increase the bus speed. Since the definition of a utility is a frequency which is too strong to influence, the engine will remain at full fuel. Isochronous governor control is impractical when paralleling with a utility because a speed setting above utility frequency, by however small an amount, would call for full rack, since the actual speed could not reach the reference speed. Similarly, if the setting were even slightly below actual speed, the racks would go to fuel-off position. Governors should not be paralleled isochronously with any system so big that the governed unit cannot affect the speed of the system. Droop provides the solution to this problem. Droop causes the governor speed reference to decrease as load increases. This allows the governor to vary the load since the speed cannot change (see Figure 3).
Governor Speed Setting Determines Load When paralleled with a bus, the load on an engine is determined by the reference speed setting of the droop governor. Increasing the speed setting cannot cause a change in the speed of the bus, but it will cause a change in the amount of load the engine is carrying. The graph shows that the amount of load is determined by where the droop line intersects the speed of the bus. If the location of this line is moved, either by changing the reference speed or the amount of droop in the unit, the amount of load will also be moved. Notice that the amount of droop set in the governor has little effect on the ability of the governor reference speed setting to determine the amount of load the engine will carry. The greater the droop the less sensitive engine load will be to speed setting. However, excessive droop presents the possibility of overspeed should the engine be removed from the bus, thus becoming unloaded. In most cases, 4% droop is adequate to provide stability and also allow for precise loading of the engine (see Figure 4).
Identical engines can show different characteristics if droop settings are not identical. An engine with more droop will require a greater change in the speed setting to accomplish a given change in load than will an engine with less droop in the governor. As explained in the following paragraphs, the amount of droop is also controlled by the amount of terminal shaft travel used between no load and full load. Both of these considerations should be investigated when apparently identical units show different responses to changes in the reference speed.
Output Shaft Movement The amount of droop in a governor is also influenced by the amount of available output shaft movement used. The governor's speed reference is changed by feedback from the position of the governor output. A governor with 4% droop over the full travel of the output shaft will have an effective droop of only 2% if only half of the output is used from minimum to maximum fuel. Two percent droop is probably not enough to provide stability in many operations. Using less than the optimum amount of terminal shaft movement will require a higher droop adjustment (knob or slider) than other engines, increasing the danger of overspeed should the generator suddenly become separated from the bus (load). The low amount of governor travel may also cause the engine to be unstable. Multiple Engine Isolated Bus Droop may also be used to parallel multiple engines on an isolated bus. In this case, the engines are capable of changing the frequency of the bus, and if all engines are operating in droop, the speed of the bus will change with a change in load. This is satisfactory only in cases where variations in the speed are acceptable. Multiple engines can also be paralleled on an isolated bus with all but one of the engines in droop and that one engine in isochronous. These systems will be able to maintain a constant speed as long as the isochronous engine is capable of accommodating any load changes (see Figure 5).
In these cases, should load decrease below the combined load setting of the droop engines, the isochronous engine will completely unload, and the system frequency will increase to the point that load equals the combined droop setting of the droop engines. The isochronous engine would be motored in this instance unless it was automatically removed from the bus. If the load increases beyond the capacity of the isochronous unit, the entire system will slow to the point where the combined droop of the other units meets the droopspeed position. In this case, the isochronous unit would remain overloaded to a point where it was unable to achieve the governor reference speed. Negative Droop As has been stated, all mechanical governors use droop, either constant or in the case of isochronous governors temporary, to achieve stable engine control. It is possible to adjust negative droop (speed reference increases as load increases) into some governors. Satisfactory governor control (engine stability) cannot be achieved with negative droop adjusted into a governor. Source: http://www.woodward.com/
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Zone4info - SIZING YOUR GENERATOR
SIZING YOUR GENERATOR Posted by Brown John June 12
It's important to match the size of your generator to your electrical needs. An undersized generator won't last long and can destroy motors and other electrical equipment that require more current than the generator can deliver. Generators are rated by their maximum electrical power output in kilowatts. (A kilowatt equals 1,000 watts, or enough energy to light 10 100-watt light bulbs.) For greatest efficiency and to prolong your generator's life, operate it at no more than 75 percent of its capacity. To calculate the generator size you need, total the wattage of the appliances and other items you want to simultaneously power and then double that number. If you plan to power several appliances, you need to account for their starting or "surge" requirements. You can find this information on the appliance or in its manual. Most homeowners will need a 5-kilowatt portable generator to power a heating system and a few other essentials (a furnace uses from about 1,800 watts to 3,500 watts, depending on the type of furnace and the size of the house). A generator of this size will cost at least $600 and, when running at 50percent load, wlll consume about half a gallon of gasoline per hour. Larger portable generators use more fuel and cost up to $3,000. Permanent standby generators with automatic operation generally cost between $2,200 and $10,000.
Take Print Zone4info - Introduction to Electrical Networks Smart. Extract from the book "Energy for the XXI Century".
Introduction to Electrical Networks Smart. Extract from the book "Energy for the XXI Century". Posted by Mark David June 10
Introduction to Electrical Networks Smart. Extract from the book "Energy for the XXI Century". Intelligent Power NetworksGrids or smart SmartGrids in its Saxon sense, provide opportunities hard to imagine just a few years ago. It is still premature to see what the potential will become reality and which not. From a minimum of adjustment of the electrical system in a structural change, there is a wide range to explore. Greater or lesser degree of penetration of renewable, more or less centralized control, degree of interconnection and meshing both low voltage and high, are just some examples.Probably coexist for years to various alternative solutions to technological and non-technical individuals in each region. But despite the doubts and uncertainties reasonable today, it seems clear that the way we provide energy longer be understood as we think today. This change affects its intensity across all agents of the electrical system. From producers to users. From engineers to regulators. And the relative contribution of each end by emphasizing one or another aspect when objectify it.In brief, we can understand how Smartgrids the confluence of energy technology and information technology and communication to an electrical system more flexible and modular, with more supply and quality of service, greater penetration of renewable energies and reduced environmental impact.SmartGrid is therefore a concept of mind. While it is during the decade 2010-2020 when placed on a large scale change, the reality is that today, mainly in the U.S. and Asia, are running very ambitious plans to give intelligence to the electricity networks. Plans to support the budget and public investment much depth by as much energy as the major telecommunications companies worldwide. From General Electric, Google, is giving a boost to irreversible electrical system.But are still many barriers that exist. Some technologies, such as energy storage, but also non-technological, whether administrative, economic or social. And even then already beginning to see some real examples at home, such as the installation of solar and wind power, the smart electric meter or energy efficiency, to name just a few examples.But behind these barriers can see real opportunities. For companies, for society, but also for countries such as Catalonia, have a good position to lead a priori part of this technological and social change.This opportunity, however, neither made nor will be gifted. It must work and fight it. Catalonia has a long entrepreneurial tradition, and especially in the electric field andenergy, where the forge pioneering vision allowed the industrial revolution that has so marked throughout the twentieth century.If we manage this legacy, however, should the administration, companies and society as a whole and the research world is to avert this situation an opportunity for the country. We are on time, but we must act decisively. Prepared by: Zone4info.com Team
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Zone4info - Autotransformers
Autotransformers
Posted by Johan column June 7
Autotransformers Autotransformers are frequently used in power applications to interconnect systems operating at different voltage classes, for example 400 kV to 220 kV for transmission. They are also often used for providing conversions between the two common domestic main voltage bands in the world (400, 200, 66 kV). The links between the UK 400 kV and 275 kV `SuperGrid` networks are normally three-phase autotransformers with taps at the common neutral end. Autotransformers are built with common main winding and a separate low voltage winding. Auto transformers are tailor-made products and the design varies with the impedance levels (constant Ohmic and constant percentage), transmission voltage and cooling requirements. These are normally provided with on load tap changer for voltage variation. For long distance rural power distribution lines, special autotransformers with automatic tap-changing equipment are inserted as voltage regulators, so that customers at the far end of the line receive the same average voltage as those closer to the source. The variable ratio of the autotransformer compensates for the voltage drop along the line. We offer a wide range of products for single phase as well as three phase transformers considering transport limitations in some countries and also as per customer requirements. Source: http://www.cgglobal.com/
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Zone4info - Power system operation
Power system operation Posted by Johan column June 6
Power system operation In power system control today the operating point is validated by a state estimator and tools to calculate system collapse limit. There are different software tools developed for this. In the experience with implementing a voltage security assessment tool at B.C. Hydro, Burnaby, Canada is described. In Sweden today SPICA is used to calculate the voltage collapse limits. SPICA is developed by Swedish National Grid (Svenska Kraftn) and uses an estimate to calculate the voltage collapse limits by load-ow calculations. Mainly by increasing the load in sensitive parts of the system and exposing them for for a selection of (n - 1) faults. The predictor proposes changes in such as, 1. Transfer limits 2. Increased production 3. Decreased export by HVDC, if the estimated operating point does not fulll the (n - 1) condition. The limitations with the state estimators are that they use a model of the power system. There is always a difference between the model and the real system. It is also common to use load-ow calculations. In a load-ow calculation the dynamic part of the elements in the model are neglected e.g. load dynamic and also often voltage regulators and current limiters. The load-ow solver calculates an operating point where there is balance in active and reactive power. There is a difference between load-ow calculation and dynamic simulation. When the operating condition changes, e.g. by a shortcircuit of a busbar, the load-ow solver calculates the operating point after clearance of the fault. The dynamic simulation also analyzes the effect by e.g. automatic equipment. Hence the operating point after the transients are settled will be different compared with a load-ow calculation. This can result in that the operating point calculated by load-ow is stable but if the scenario is analyzed by dynamic simulation a blackout can occur in the transient phase. Prepared By: Zone4info.com
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Zone4info - LOCAL IMPACTS OF WIND POWER
LOCAL IMPACTS OF WIND POWER Posted by Johan column June 6
1. 2. 3. 4.
Wind power locally has an impact on the following aspects of a power system: branch flows and node voltages protection schemes, fault currents and switchgear ratings harmonics flicker The first two topics must always be investigated when connecting new generation capacity to a power system. This applies independently of the prime mover of the generator and the grid coupling, and these issues are therefore not specific for wind power but apply to all cases where a generator is connected to a grid. The third topic is particularly of interest when generators that are grid coupled through a power electronic converter are used. For wind power, it does therefore mainly apply to variable speed turbines. Further, it applies to other converter connected generation equipment, such as photovoltaics and small scale CHP (combined heat and power) systems that often use high speed synchronous generators grid interfaced with power electronics. The last topic is specific for wind turbines, particularly for constant speed turbines, as will be argued below. The way in which wind turbines affect the voltages at nearby nodes depends on whether they are constant speed or variable speed turbines. The squirrel cage induction generator in constant speed turbines has a fixed relation between rotor speed, active power, reactive power and terminal voltage. Therefore, it cannot effect its terminal voltage by changing the reactive power exchange with the grid. Additional equipment such as capacitor banks, SVCs (Static Var Compensators) or STATCOMs (STATic COMpensators) is hence necessary for voltage control. On the other hand, variable speed turbines have, at least in theory, the capability of varying the reactive power at a given active power, rotor speed and terminal voltage. However, the range over which the reactive power can be controlled depends on the size of the power electronic converter. Direct drive variable speed turbines often have an advantage here. They already have a large converter and some extra capacity to allow reactive power control can be added at marginal cost. Doubly fed induction generator based turbines in general have the advantage that a small converter can be used. Adding converter capacity to allow reactive power control tends to cancel this advantage of course. The contribution of wind turbines to the fault current is also different for the three main wind turbine types. Constant speed turbines are equipped with a directly grid coupled squirrel cage induction generator. They therefore contribute to the fault current and rely on conventional protection schemes (overcurrent, overspeed, over- and undervoltage, over- and underfrequency). Turbines based on the doubly fed induction generator also contribute to the fault current. However, the control system of the power electronics converter that controls the rotor current measures the grid voltage at a very high sampling rate (several kHz). A fault is therefore detected very quickly. Due to the sensitivity of power electronics to overcurrents, this wind turbine type is at present quickly disconnected when a fault occurs. Thus, although a doubly fed induction generator based wind turbine contributes to the fault current, the duration of its contribution is rather short. Wind turbines with a direct drive generator hardly contribute to the fault current at all, because the power electronic converter through which such a turbine is connected to the grid cannot carry a fault current. It is therefore normal practice that these turbines are also quickly disconnected in case of a fault. The third topic, harmonics, is mainly an issue in the case of variable speed turbines, because these are equipped with power electronics, the main source of harmonics. However, in case of modern power electronics converters with their high switching frequencies and advanced control algorithms and filtering techniques, the harmonics issue should not be a major problem. Well-designed synchronous and
asynchronous generators hardly emit any harmonics. Harmonics are therefore no issue for constant speed wind turbines that use directly grid coupled squirrel cage induction generators. The flicker problem is typical for wind turbines. Wind is a quite rapidly fluctuating prime mover. In constant speed turbines, prime mover fluctuations are directly translated into output power fluctuations, because there is no energy buffer between mechanical input and electrical output. Depending on the strength of the grid connection, the resulting power fluctuations can result in grid voltage fluctuations, which can cause unwanted and annoying fluctuations in bulb brightness. This problem is referred to as flicker. In general, no flicker problems occur with variable speed turbines, because in these turbines wind speed fluctuations are not directly translated into output power fluctuations. The controller of the power electronics in these wind turbines derives a set point for active power from the rotor speed. Hence, only if the rotor speed varies, the active power is changed. Due to the rotor inertia, the rotor acts as an energy buffer or low pass filter. Rapid wind speed fluctuations hardly effect the rotor speed and are therefore hardly observed in the output power. The local impacts of the various wind turbine types are summarized in table
Prepared By: Zone4info.com Team Source: Wind Power System Modelling
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Zone4info - Wind Power Generation versus Conventional Power Generation
Wind Power Generation versus Conventional Power Generation Posted by Johan column June 6
Wind Power Generation versus Conventional Power Generation "There are principal differences between wind power on the one hand and conventional generation on the other: In wind turbines, generating systems different from the synchronous generator used in conventional power plants are applied. The prime mover of wind turbines, i.e. the wind, cannot be controlled, and fluctuates randomly. Up to this moment, the generated power of wind turbines is completely determined by the wind speed and not controlled any further. An additional difference is that the typical size of wind turbines is much lower than that of a conventional power plant. These differences between conventional and wind power generation are reflected in a different interaction with the power system, the topic discussed now. In the analysis in the next section, a distinction is made between local and system wide impacts of wind power. Local impacts of wind power are impacts that occur in the (electrical) vicinity of a wind turbine or wind park that can be attributed to a specific turbine or park, . of which the cause can be localized. These effects occur at each turbine or park, independently of the overall wind power penetration level in the system as a whole. When the wind power penetration level in the whole system is increased, the local effects occur in the vicinity of each turbine or park, but when the (electrical) distance is large enough, adding wind power on one location does not affect the local impacts of wind power elsewhere. Only adding turbines locally increases the local impacts. Further, the local impacts differ for the three main wind turbine types. System wide impacts, on the other hand, are impacts of which the cause can not be localized. They are a consequence of the application of wind power that can, however, not be attributed to individual turbines or parks. Nevertheless, they are strongly related to the penetration level in the system as a whole. However, in opposition to the local effects, the level of geographical spreading of the wind turbines and the applied wind turbine type are less important. Prepared By: zone4info.com Reference: Wind Powr Modelling
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Zone4info - Neutral Grounding Resistors
Neutral Grounding Resistors Posted by Brown John June 5
Neutral Grounding Resistors are used for resistance grounding industrial power system. They are generally connected between ground and neutral of transformers, generators and grounding transformers. Neutral grounding resistors are used in order to limit maximum fault current to a value which will not damage the equipment in the power system, yet allow sufficient flow of fault current to operate protective relays to clear the fault. Although it is possible to limit fault currents with high resistance neutral grounding resistors, earth short circuit currents can be extremely reduced. as a result of this fact protection devices may not sense the fault. Therefore, it is the most common application to limit single phase fault currents with low resistance neutral grounding resistors to approximattely rated current of transformer and / or generator.
Example: A 10000 kVA 13.8 kV generator's rated current is 419 A. Therefore, 400 A or 500 A Neutral Grounding Resistor is generally considered as suitable for that application Prepared By: Brown
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Zone4info - Why Conventional Power Plants are Still Needed
Why Conventional Power Plants are Still Needed Posted by Brown John June 5
Why Conventional Power Plants are Still Needed As the previous section laid out, energy demand in the United States is going to continually increase even with conservation policies, technology, and increasing energy prices. This increased demand along, with a reduction in generation capacity due to limitations and closure of aging coal, oil, and nuclear plants, will create a gap between generation capacity and demand that will have to be met with new renewable sources, newly built conventional power plants, or a combination of the two. There are great minds such as Larry Page at Google and Ray Kurzweil who believe that our future energy needs will be provided by improving renewable energy technologies. Larry Page and Google are investing millions of dollars to develop solar thermal energy technology. Ray Kurzweil believes that, because photovoltaic technology is siliconbased its growth should be exponential. The capacity of photovoltaic panels is doubling every two years, therefore in approximately twenty years, or eight doublings, photovoltaics should be able to provide all of the world’s energy needs5. It would be ideal if Larry Page, Ray Kurzweil and others who believe that our future energy needs will be met through advancements in technology. However, there are other energy experts who strongly disagree that renewable are going to be able to close the energy gap. Speaking on this topic for the BBC regarding the UK’s energy future, Sir Bernard Ingham had a harsh reaction to people who are selling renewables as the only energy solution: “Anybody who is relying upon renewables to fill the gap is living in an utter dream world and is in my view an enemy of the people6.” The U.S. may have greater renewable resources, especially solar and biofuel potential, but this strong rejection of renewables as a significant replacement for conventional power plants is common among energy experts. In fact, none of the major energy forecasts, including the reference case of the AEO2010, forecast renewable technologies even keeping pace with growth, let alone replacing current capacity. The AEO2010 projects electrical generation capacity to increase from 1,008 gigawatts in 2008 to 1,216 gigawatts in 20357. This increase of 208 gigawatts is equivalent to over 200 fullsize commercial nuclear power plants or roughly 4500 typical university campus power plants such as those found at the University of Cincinnati, Purdue University, or Ohio State University. The AEO2010 projects that the largest growth will be from renewable sources and that renewable will account for 45% -65% of the increase in total generation. However, every fuel type, including coal, will continue to grow through 2035. New conventional power plants will be needed to meet increasing demand and to replace aging existing plants. The United States has significantly higher potential for renewable sources than the United Kingdom, but in his analysis of the UK’s energy future, David J.C. MacKay explains that, “any plan that doesn’t make heavy use of nuclear power or “clean coal” has to make up the energy balance using renewable power bought in from other countries8.” It is lear to David J.C. MacKay that England does not have the capacity to meet its needs with domestic renewable sources, and even though the United States is much larger it is unlikely that the entirety of its needs can be met from renewable sources in the foreseeable future. The inability for the United States to meet its future energy needs and to replace its current capacity with renewable resources is a result of several conditions. First, renewable sources such as solar and wind are too unreliable within the current infrastructure system. If the country could be develop a system that would allow areas of high production to share with areas of low production, then the
average energy production could be shared across the country. However, storage systems and distribution systems cannot adequately guarantee a continual energy supply from wind or solar. Therefore, under current regulations utilities that built a solar panel or wind turbine must also build a conventional plant of equal capacity to guarantee energy delivery to the customer. This requires high capital investment that provides little gain. Secondly, with current technology and even projected technology there simply is not enough land area to give to solar and wind and still have a healthy agriculture industry, wood and forest industry, and access for other land uses. This is especially true when considering the third problem of economics. Even in places where there is technology available, to make use of wind or solar to replace the current generation systems, it would be extremely cost prohibitive. By: Andrew J. Ellis
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Zone4info - Dual-Feeder System
Dual-Feeder System
Posted by Ackerley Acton June 4
In some areas, usually metropolitan centers, two utility company power drops can be brought into a facility as a means of providing a source of standby power. As shown in Figure , two separate utility service drops â&#x20AC;&#x201D; from separate power-distribution systems â&#x20AC;&#x201D; are brought into the plant, and an automatic transfer switch changes the load to the backup line in the event of a main-line failure. The dual-feeder system provides an advantage over the auxiliary diesel arrangement in that power transfer from main to
The classic standby power system using an engine-generator set. This system protects a facility from prolonged utility company power failures.
The use of a static transfer switch to transfer the load from the utility company to the on-site generator.
The dual-utility-feeder system of ac power loss protection. An automatic transfer switch changes the load from the main utility line to the standby line in the event of a power interruption. standby can be made in a fraction of a second if a static transfer switch is used. Time delays are involved in the diesel generator system that limit its usefulness to power failures lasting more than several minutes. The dual-feeder system of protection is based on the assumption that each of the service drops brought into the facility is routed via different paths. This being the case, the likelihood of a failure on both power lines simultaneously is remote. The dual-feeder system will not, however, protect against areawide power failures, which can occur from time to time. The dual-feeder system is limited primarily to urban areas. Rural or mountainous regions generally are not equipped for dual redundant utility company operation. Even in urban areas, the cost of bringing a second power line into a facility can be high, particularly if special lines must be installed for the feed. If two separate utility services are available at or near the site, redundant feeds generally will be less expensive than engine-driven generators of equivalent capacity. Figure 21.4 illustrates a dual-feeder system that utilizes both utility inputs simultaneously at the facility. Notice that during normal operation, both ac lines feed loads, and the â&#x20AC;&#x153;tieâ&#x20AC;? circuit breaker is
A dual-utility-feeder system with interlocked circuit breakers. open. In the event of a loss of either line, the circuit-breaker switches reconfigure the load to place the entire facility on the single remaining ac feed. Switching is performed automatically; manual control is provided in the event of a planned shutdown on one of the lines. Source: Power System HandBook Prepared By: zone4info.com Team
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Zone4info - LIGHTNING ARRESTERS
LIGHTNING ARRESTERS Posted by Johan column June 2
The purpose of using lightning arresters on power lines is to cause the conduction to ground of excessively high voltages that are caused by lightning strikes or other system-problems. Without lightning arresters, power lines and associated equipment could become inoperable when struck by lightning. Arresters are designed to operate rapidly and repeatedly if necessary. Their response time must be more rapid than the other protective equipment used on power lines. Lightning arresters must have a rigid connection to ground on one side. The other side of the arrester is connected to a power line. Sometimes, they are connected to transformers or the insides of switchgear. Lightning is a major cause of power-system failures and equipment damage, so lightning arresters have a very important function. Lightning arresters are also used at outdoor substations. The lightning arrester, such as that shown in Figure 7-8, is used to provide a path to ground for lightning strikes or hits. This path eliminates the flashover between power lines, which causes short circuits. Valve-type lightning
arresters are used frequently. They are two-terminal devices in which one terminal is connected to the power line and the other is connected to ground. The path from line to ground is of such high resistance that it is normally open. However, when lightning, which is a very high voltage, strikes a power line, it causes conduction from line to ground. Thus, voltage surges are conducted to ground before flashover between the lines occurs. After the lightning surge has been conducted to ground, the valve assembly then causes the lightning arrester to become nonconductive once more.
Lightning arresters: (a) external detail; (b) internal detail; (c) placement on a wood pole. Prepared By: zone4info.com Team Source: Electrical Power Distribution
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Zone4info - Cable selection Calculation
Cable selection Calculation Posted by Johan column May 29
When a current is passed through a conductor it causes it to rise in temperature.
HEAT I N CABLES When installing circuits it is important that the correct size current carrying conductor is selected to carry the current required without causing the cable to overheat and that the voltage drop caused by the resistance of the cable is not greater than is permissible. The following calculations are designed to compensate for conductor temperature rise. We must first calculate the design current that the circuit will have to carry (Ib). Calculation is
(I being design current). A protective device must now be selected (In) this must be equal to or greater than Ib. If the cable is to be installed in areas where environmental conditions will not allow the cable to cool, correction factors will be required. Ca is a factor to be used where ambient temperature is above or below 30째C. This factor can be found in Table , appendix 4 of BS7671. If a BS3036 rewirable fuse is needed Table 4C2 should be used. Cg is a factor to be used where the cable is grouped or bunched (touching) with other cables. This factor can be found in Table 4B1, appendix 4 of BS7671. Ci is a factor for use where a conductor is surrounded by thermal insulation and can be found in Table 52A part 5 of BS7671. Cr is a factor for rewirable fuses and is always 0.725. This factor must always be used when rewirable fuses protect a circuit. The reason for the factor will be explained at end of the chapter. These factors should be multiplied together and then divided into In. Therefore the calculation is
The current carrying capacity of the cable must be equal to or greater than the result of this calculation. It should be remembered that only the correction factors that effect the cable at the same time should be used. EXAMPLE A circuit is to be installed using 2.5 mm2, 1.5 mm2 twin and earth 70°C thermoplastic cables, it is 32 metres long and protected by a BS 88 fuse. The load to be supplied is a 4.2kW kiln, the circuit is to be installed in minitrunking containing one other circuit at an ambient temperature of 35°C. Maximum permissible volt drop is 7 V. Supply is a T N S system with a Ze of 0.7 . Calculate the minimum cable that may be used. Design current
Protective device In (≥18.26), nearest BS 88 is 20 amperes. In the example, the cable is installed in plastic trunking. From BS 7671 Table 4A1 Installation methods, number 8, method 3 matches the example. The cable is installed in trunking which will contain one other circuit. Correction factor for grouping (Ca) is required from BS 7671 Table 4B1. It can be seen that for two circuits in one enclosure a factor of 0.8 must be used. The ambient temperature is 35°C. A correction factor for ambient temperature (Ca) from Table 4C1 must be used. Thermoplastic cable at 35 C a factor of 0.94. Using these factors, it is now possible to calculate the minimum size conductors required for this circuit.
Calculator method 20 ÷ (0.8 × 0.94) = 26.59 This is the minimum value of current that the cable must be able to carry to enable it to be installed in the environmental conditions affecting the cable. From Table 4D2A columns 1 and 4, it can be seen that a 4 mm2 cable has an It (current carrying capacity) of 30 amperes. A cable with 4 mm2 live conductors will carry the current in these conditions without overheating, but will it comply with the voltage drop requirements? From Table 4D2B columns 1 and 3, it can be seen that 4 mm2 cable has a voltage drop of 11 (mV/A/m) or millivolts × load current × length of circuit. As the value is in millivolts, it must be converted to volts by dividing by 1000. The circuit length is 32 metres and the load current is 18.26 amperes. Calculation
The voltage drop in this cable will be 6.42 V which is acceptable as the maximum permissible for the circuit is 7 V. The calculations which have been carried out up to this point have been to select a cable to comply with the current and voltage drop requirements for the circuit. This is only part of the calculation. It is now important that a calculation is carried out to prove that the protective device will operate within the time required if an earth fault were to occur on the circuit. The load is classed as fixed equipment, this will have a disconnection time not
exceeding 5 seconds (regulation 413-02-13). The resistance of the cable must now be calculated: A 4 mm2 twin and earth cable will have a circuit protective conductor (CPC) of 1.5mm2. From Table 9A in the On-Site Guide, it can be seen that this cable will have a resistance of 16.71 milli-ohms per metre at 20°C. As the cable could operate at 70°C the multiplier from Table 9C in the On-Site Guide must be used to adjust the resistance value from 20°C to 70°C. Calculation
The resistance of the cable at operating temperature of 70°C is 0.64 . Zs (earth loop impedance) must now be calculated. Zs = Ze + (r1 + r2) From the information given in the example, Ze (external earth loop impedance) is 0.7 ohm . Therefore, Zs = 0.7 + 0.64 Zs = 1.34 This value must now be checked against the value for maximum permissible Zs. This is in BS 7671 Table 41D for 5 second disconnection. It can be seen that the maximum Zs for a 20 A BS 88 fuse is 3.04 . As the circuit has a calculated Zs of 1.34, this will be satisfactory. Download (BS 7671:2008) Books Source: Electrical Installation by A.J.Watkins Prepared by: zone4info Team
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Zone4info - Live polarity test
Live polarity test
Posted by Johan column May 28
Live polarity test This test is usually carried out at the origin of the installation before it is energized to ensure that the supply is being delivered to the installation at the correct polarity. The instrument to be used is an approved voltage indicator or test lamp that complies with HSE document GS 38. It is acceptable for an earth loop impedance meter to be used as these instruments also show polarity. Great care must be taken whilst carrying out this test as it is a live test. STEP 1 Place the probes of the voltage indicator onto the phase and neutral terminal of the incoming supply at the main switch. The device should indicate a live supply.
STEP 2 Place the probes of the voltage indicator onto the phase and earth terminal of incoming supply at the main switch. The device should indicate a live supply.
STEP 3 Place the probes of the voltage indicator onto the earthing terminal and the neutral terminal at the main switch. The device should indicate no supply.
Source: Electrical Installation Guid. Prepared By: Column
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Zone4info - What is earth and why and how do we connect to it?
What is earth and why and how do we connect to it? Posted by Johan column May 25
What is earth and why and how do we connect to it? The thin layer of material which covers our planet â&#x20AC;&#x201C; rock, clay, chalk or whatever â&#x20AC;&#x201C; is what we in the world of electricity refer to as earth. So, why do we need to connect anything to it? After all, it is not as if earth is a good conductor. It might be wise at this stage to investigate potential difference (PD). A PD is exactly what it says it is: a difference in potential (volts). In this way, two conductors having PDs of, say, 20 and 26 V have a PD between them of 26 - 20 = 6 V. The original PDs (i.e. 20 and 26 V) are the PDs between 20 V and 0 V and 26 V and 0 V. So where does this 0 V or zero potential come from? The simple answer is, in our case, the earth. The definition of earth is, therefore, the conductive mass of earth, whose electric potential at any point is conventionally taken as zero. Thus, if we connect a voltmeter between a live part (e.g. the line conductor of a socket outlet) and earth, we may read 230 V; the conductor is at 230 V and the earth at zero. The earth provides a path to complete the circuit. We would measure nothing at all if we connected our voltmeter between, say, the positive 12 V terminal of a car battery and earth, as in this case the earth plays no part in any circuit.
So, a person in an installation touching a live part whilst standing on the earth would take the place of the voltmeter and could suffer a severe electric shock. Remember that the accepted lethal
level of shock current passing through a person is only 50 mA or 1/20 A. The same situation would arise if the person were touching a faulty appliance and a gas or water pipe ( Figure 3.3 ). One method of providing some measure of protection against these effects is, as we have seen, to join together (bond) all metallic parts and connect them to earth. This ensures that all metalwork in a healthy installation is at or near 0 V and, under fault conditions, all metalwork will rise to a similar potential. So, simultaneous contact with two such metal parts would not result in a dangerous shock, as there would be no significant PD between them. Unfortunately, as mentioned, earth itself is not a good conductor, unless it is very wet. Therefore, it presents a high resistance to the flow of fault current. This resistance is usually enough to restrict fault current to a level well below that of the rating of the protective device, leaving a faulty circuit uninterrupted. Clearly this is an unhealthy situation. In all but the most rural areas, consumers can connect to a metallic earth return conductor, which is ultimately connected to the earthed neutral of the supply. This, of course, presents a lowresistance path for fault currents to operate the protection. In summary, connecting metalwork to earth places that metal at or near zero potential and bonding between metallic parts puts such parts at a similar potential even under fault conditions. Add to this a low-resistance earth fault return path, which will enable the circuit protection to operate very fast, and we have significantly reduced the risk of electric shock. Source: Electrical Wiring 13th Edition Prepared by: zone4info.com team
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Zone4info - Characteristics of TT, TN and IT systems
Characteristics of TT, TN and IT systems Posted by Johan column May 24
The TT system:
Technique for the protection of persons: the exposed conductive parts are earthed and residual current devices (RCDs) are used Operating technique: interruption for the first insulation fault Note: If the exposed conductive parts are earthed at a number of points, an RCD must be installed for each set of circuits connected to a given earth electrode. Main characteristics public LV distribution network.Simplest solution to design and install. Used in installations supplied directly by the RCDs may be necessary). Does not require continuous monitoring during operation (a periodic check on the which also prevent the risk of fire when they are set to i 500 mA. Protection is ensured by special devices, the residual current devices (RCD), outage is limited to the faulty circuit by installing the RCDs in series (selective RCDs)or in parallel (circuit selection).Each insulation fault results in an interruption in the supply of power, however the currents, require special measures to avoid nuisance tripping, i.e. supply the loads Loads or parts of the installation which, during normal operation, cause high leakagewith a separation transformer or use specific RCDs (see section 7.1 in chapter F). The TN system: Technique for the protection of persons:
conductive parts and the neutral are mandatory Interconnection and earthing of exposed Interruption for the first fault using overcurrent protection (circuit breakers or fuses) Operating technique:
interruption for the first insulation fault
Main characteristics Generally speaking, the TN system: requires the installation of earth electrodes at regular intervals throughout the installation Requires that the initial check on effective tripping for the first insulation fault becarried out by calculations during the design stage, followed by mandatorymeasurements to confirm tripping during commissioning Requires that any modifications or extension be designed and carried out by aqualified electrician May result, in the case of insulation faults, in greater damage to the windings ofrotating machines May, on premises with a risk of fire, represent a greater danger due to the higherfault currents In addition, the TN-C system: At first glance, would appear to be less expensive (elimination of a device pole and of a conductor) Requires the use of fixed and rigid conductors Is forbidden in certain cases: Premises with a risk of fire For computer equipment (presence of harmonic currents in the neutral) In addition, the TN-S system: Due to the separation of the neutral and the protection conductor, provides a clean PE (computer systems and premises with special risks) IT system: Protection technique: Interconnection and earthing of exposed conductive parts Indication of the first fault by an insulation monitoring device (IMD) Interruption for the second fault using over current protection (circuit breakers or fuses) Operating technique: Monitoring of the first insulation fault v Mandatory location and clearing of the fault Interruption for two simultaneous insulation faults
Main characteristics Solution offering the best continuity of service during operation Indication of the first insulation fault, followed by mandatory location and clearing,ensures systematic prevention of supply outages Generally used in installations supplied by a private MV/LV or LV/LV transformer Requires maintenance personnel for monitoring and operation Requires a high level of insulation in the network (implies breaking up the network if it is very large and the use of circuit-separation transformers to supply loads with high leakage currents) The check on effective tripping for two simultaneous faults must be carried out by calculations during the design stage, followed by mandatory measurements during commissioning on each group of interconnected exposed conductive parts Protection of the neutral conductor must be ensured as indicated in section Source: Shneider Electric Prepared: zone4info.com Team
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Zone4info - Zig Zag Grounding Transformer
Zig Zag Grounding Transformer Posted by Zone 4info May 24
Zig Zag Grounding Transformer A Zig Zag Grounding Transformer is often used as a ground source on the delta side of a transformer or as a ground path for an ungrounded â&#x20AC;&#x153;Y.â&#x20AC;? A few of the most common benefits of a Zig Zag Grounding Transformer include the following: Allows the connection of neutral to phase loads. Hinders the probability of transient over voltages in the scenario of re-striking ground faults. Allows ground fault currents a path during line to ground faults. Maintains near ground potential or system neutral with a low impendence path to ground. The Zig Zag Grounding Transformer over current relays are connected to deltaconnected CTs. These configurations are used for protection of the current flow for an external ground fault. If a single line-to-ground fault occurs on an ungrounded or isolated system, there is no return path for fault current and no current flows. Although the system is still operational in this scenario, the other two lines that are not faulted rise in voltage by the square root of three, which results in overstressing of the transformer by 173 percent. A Zig Zag Grounding Transformer provides the ground path to prevent this situation. In applications where the transformers are switched, to prevent inadvertent tripping upon energizing the transformer, harmonicrestrained over current relays may be used.
Zig Zag Ground Transformer Construction The construction of a Zig Zag Grounding Transformer will include a connected winding with or without an auxiliary winding. A major benefit inherent in the design of the Zig Zag GroundingTransformer is the limitation of circulation of third harmonics. The Zig Zag Grounding Transformer can be used without the 4- or 5-leg core design or the Delta connected winding normally used in power distribution transformers. Elimination of a secondary winding provides the added benefits of economy and smaller size when compared to a two winding ground transformer. A zig zag grounding transformer can also provide ground in a smaller unit than a two-winding wye-delta transformer with the same zero sequence impedance. It is also good to note that a Zig Zag Grounding Transformer can be provided with the ability to provide auxiliary power to either a wye or delta connected load. It is also good to note that a Zig Zag Grounding Transformer can be provided with the ability to provide auxiliary power to either a wye or delta connected load.
Parameters For Your Zig Zag Grounding Transformer Some of the basic parameters for determining the perfect zig zag ground transformer for your application include knowing your primary voltage, rated kVA, continuous neutral current, fault current/duration, impedance, primary winding connection, and secondary winding.
Source: Internet Prepared by Zone4info.com Team
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Zone4info - History drives - drives with reversing excitation "M417C004"
History drives - drives with reversing excitation "M417C004" Posted by Mark David May 23
Technically very interesting solution, which is now apparently not. Increase in nominal output drive speed can be increased only by armature voltage, which is limited to reversing the bridge was not good at 375V. These drives are used exactly where it was needed performance at high armature voltage, so the engine was reticulated to 440V for the anchor. This was to ensure only the sets either WL or nereverzaÄ?nĂm then anchor the bridge to the engine is able to supply the required armature voltage at rated speed. Later, have now emerged as ways to do this even when reversing anchor the bridge, but we will not anticipate. The drive was also produced in MEZ Vsetin, should be described as type "C", thus reversing excitation. Production ended in the early nineties, when the power I'm not mistaken.
The drive M417C004 served to drive the carousel plate SKQ8 TOS Hulin.Cabinet was double, because even include auxiliary circuits and the carousel was fitted on both sides, ie front and rear. In this particular case from the back side will not see anything, because everything was built on pallets.
The necessary signaling clockwise on the cabinet door, which you just unnoticed, because the switchboard was located beside the machine. On the right are but two indicators of drive failures, which signaled the failure of white on the right drive cooling, ie the aforementioned air valve, yellow to the left then fuse failure in the anchor circuit, as we shall see below
Thyristor bridge anchors, non-reversing, ie with six thyristors. The fuses are in a version with an alarm, these are the bars with the micro fuse, fuse failure is folded, or unzipped the circuit in the inverter and control light on the door. Transformers at the bottom to synchronize and generate a spark pulse thyristors.Each thyristor is located ignition transformer and suppression RC members.
As each thyristor bridge and took the 3-phase reactor (choke). It is gray with the capacitors, which should ensure interference suppression drives in EMC.Below is seen the main reactor power contactor 160A, left, then two anchor fuses and shunt current measurement from the anchor.
The main controller, very similar to the drive "E" then reversing over the anchor.Most plates were identical, depend only on their own setting. Feedback engine speed tachometer K10A6 was implemented which gave 80VDC/1000 speed. Later he was transferred to a lower voltage, because at several thousand revolutions has been the DC feedback voltage is high enough It worked like this. If you request to change direction at full voltage regulator anchor anchor block, to minimize the excitation current, and when he disappeared, which lasted long enough, the alarm is still a large inductance, switched to the opposite bridge excitation, thus changing the direction of excitation current, and released anchor. With this change, he was an anchor in the inverter bridge mode and the engine slowed to a network. Once the speed change, he moved smoothly into bridge mode and the motor current supplied to the engine start in the opposite direction. So
much for the principle of reversing a DC motor through the alarm. As stated in the introduction, today, this principle no longer used, or at least know about it.
The signals from the controller have been decorated in the bottom of over four flat connectors.They were quite reliable.
Control and power had dominated all the transformers, the switching power supply was not even speech. Here is a little seen installation of control panels and the rear of the cabinet.
These modular relay control in RPxx drive were everywhere present. Most failures were at the time variations of these relays, one of which is partially visible at the far right. Round connectors at the bottom of the then Russian options, but quite functional.
And then that's how it all came in a double box 2 meters high. Conclusion: This particular drive was manufactured in 1983, thirty years ago and still works with many original parts. Just keep the DC motor, where it is necessary to check the carbon brushes, commutator, armature bearings and the like. And the ventilation of the engine, because there is nothing worse than when the engine is too "baked". The repair is then very expensive. Source: Internet Prepared by : Electrical Contributor
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Zone4info - Testing for continuity of protective conductors
Testing for continuity of protective conductors Posted by Brown John May 23
Testing for continuity of protective conductors
Main equipotential bonding This test is carried out to ensure that the equipotential bonding conductors are unbroken, and have a resistance low enough to ensure that, under fault conditions, a dangerous potential will not occur between earthed metalwork (exposed conductive parts) and other metalwork (extraneous conductive parts) in a building. It is not the purpose of this test to ensure a good earth fault path but to ensure that, in the event of a fault, all exposed and extraneous conductive parts will be live at the same potential, hence EQUIPOTENTIAL bonding. In order to achieve this, it is recommended that the resistance of the bonding conductors does not exceed 0.05 . Table 54H of the On-Site Guide and Regulation 547-02-02 in BS 7671 cover the requirements of equipotential bonding. Table 10A of the On-Site Guide is also useful. Maximum lengths of copper bonding conductors before 0.05W is exceeded. Size mm2 Length in metres 10 27 16 43 25 68 35 95 The test is carried out with a Low Resistance Ohm meter and often can only be carried out on the initial verification; this is because one end of the bonding conductor must be disconnected to avoid parallel paths. When disconnecting a bonding conductor, it is important that the installation is isolated from the supply. On larger installations it is often impossible to isolate the installation and, therefore, the conductor must remain in place. The instrument should be set on the lowest value of W possible. STEP 1 Isolate supply (as safe isolation procedure)
STEP 2 Disconnect one end of the conductor (if possible, disconnect the conductor at the consumers unit, and test from the disconnected end and the metalwork close to the bonding conductor. This will test the integrity of the bonding clamp).
STEP 3 Measure the resistance of test leads or null leads (these may be long as the only way that we can measure a bonding conductor is from end to end).
STEP 4 Connect one test lead to the disconnected conductor at the consumerâ&#x20AC;&#x2122;s unit. Note: Safety notice removed for clarity.
STEP 5 Connect the other end of the test lead to the metalwork that has been bonded (connecting the lead to the metalwork and not the bonding clamp will prove the integrity of the clamp).
STEP 6 If the instrument is not nulled remember to subtract the resistance of the test leads from the total resistance. This will give you the resistance of the bonding conductor. If the meter you are using has been nulled, the reading shown will be the resistance of the conductor.
STEP 7 Ensure that the bonding conductor is reconnected on completion of the test. Whilst carrying out this test a visual inspection can be made to ensure that the correct type of BS 951 earth clamp, complete with label is present, and that the bonding conductor has not been cut if it is bonding more than one service.
If the installation cannot be isolated on a periodic inspection and test, it is still a good idea to carry out the test; the resistance should be a maximum of 0.05 as any parallel paths will make the resistance lower. If the resistance is greater than 0.05 the bonding should be reported as unsatisfactory and requires improvement. In some instances the equipotential bonding conductor will be visible for its entire length; if this is the case, a visual inspection would be acceptable, although consideration must be given to its length. For recording purposes on inspection and test certificates no value is required but verification of its size and suitability is.
Items to be bonded would include any incoming services, such as: water main, gas main, oil supply pipe, LPG supply pipe. Also included would be structural steel work, central heating system, air conditioning, and lightning conductors within an installation (before bonding a lightning conductor it is advisable to seek advice from a specialist). This is not a concise list and consideration should be given to bonding any metalwork that could introduce a potential within a building. Prepared By: Zone4info Team Source: Practical Installation Handbook
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Zone4info - The main earthing terminal
The main earthing terminal Posted by Johan column May 22
The main earthing terminal
The intake arrangements shown in Figures 2.1–2.4 all indicate a main earthing terminal separate from the consumer unit. In fact, most modern units have an integral earth bar, which can accommodate all the circuit earths or circuit protective conductors (cpc’s), the earthing conductor and the main protective bonding conductors. However, it is probably more convenient to have a separate main earthing terminal to which is connected the earthing conductor from the consumer unit, the earthing conductor to the means of earthing (earth electrode, cable sheath, etc.) and the main protective bonding conductors. This arrangement is particularly useful when an installation is under test. As mentioned, the main earthing terminal is a point to which all main protective bonding conductors are connected. These conductors connect together gas, water and oil services etc., and in so doing, maintain such services within the premises at or about earth potential (i.e. 0 V). It must be remembered that bonding the installation earthing to these services is not done to gain an earth many services are now run in non-metallic materials and it is within the premises that bonding is so very important. From a practical point of view, bonding of gas services should be carried out within 600 mm of the gas meter on the consumer’s side of the meter , and as near as possible to the water intake position, once again on the consumer’s side ( Figure 2.5 ).
There is no reason why bonding to main services should be carried out individually and separately, provided that the bonding conductors are unbroken. This will prevent conductors being accidentally pulled out of the bonding clamp terminal, leaving one or other of the services unbonded ( Figure 2.6 ). Main Isolation The main intake position houses, usually as part of the consumer unit, the means to isolate the supply to the whole installation, and there is a requirement to ensure that such isolation be accessible
at all times. So the means of isolation should not be housed in cupboards used for general household storage. Unfortunately, the design of many domestic premises tends to relegate this important equipment to areas out of sight and inaccessible to the occupier. Prepared by: Zone4info.com Team Source: Electric Wiring Design Book
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Zone4info - Methodology of power system
Methodology of power system Posted by Zone 4info May 22
General design - Regulations - Installed power: Listing of power demands The study of a proposed electrical installation requires an adequate understanding of all governing rules and regulations. The total power demand can be calculated from the data relative to the location and power of each load, together with the knowledge of the operating modes (steadystate demand, starting conditions, nonsimultaneous operation, etc.) From these data, the power required from the supply source and (where appropriate) the number of sources necessary for an adequate supply to the installation are readily obtained. Local information regarding tariff structures is also required to allow the best choice of connection arrangement to the power-supply network, e.g. at high voltage or low voltage level.
Connection to the HV utility distribution network
This connection can be made at: Connection to the HV utility distribution network A consumer-type substation will then have to be studied, built and equipped. This substation may be an outdoor or indoor installation conforming to relevant standards and regulations (the low-voltage section may be studied separately if necessary). Metering at high-voltage or low-voltage is possible in this case. Low-voltage service connections The installation will be connected to the local power network and will (necessarily) be metered according to LV tariffs.
Distribution within a low-voltage installation
The whole installation distribution network is studied as a complete system. The number and characteristics of standby emergency-supply sources are defined. Neutral earthing arrangements are chosen according to local regulations, constraints related to the power-supply, and to the type of loads The distribution equipment (panelboards, switchgears, circuit connections, ...) are determined from building plans and from the location and grouping of loads. The type of premises and allocation can influence their immunity to external disturbances.
Protection against electric shock
The earthing system (TT, IT or TN) having been previously determined, then the appropriate protective devices must be implemented in order to achieve protection against hazards of direct or indirect contact.
The protection of circuits
Each circuit is then studied in detail. From the rated currents of the loads; the level of short-circuit current; and the type of protective device, the cross-sectional area of circuit conductors can be determined, taking into account the nature of the cableways and their influence on the current rating of conductors. Before adopting the conductor size indicated above, the following requirements must be satisfied: c The voltage drop complies with the relevant standard c Motor starting is satisfactory c Protection against electric shock is assured The short-circuit current Isc is then determined, and the thermal and electrodynamic withstand capability of the circuit is checked. These calculations may indicate that it is necessary to use a conductor size larger than the size originally chosen. The performance required by the switchgear will determine its type and characteristics. The use of cascading techniques and the discriminative operation of fuses and tripping of circuit breakers are examined.
Protection against overvoltages
Direct or indirect lightning strokes can damage electrical equipment at a distance of several kilometers. Operating voltage surges and transient industrial frequency voltage surges can also produce the same consequences.The effects are examinated and solutions are proposed.
Power factor improvement and harmonic filtering
The power factor correction within electrical installations is carried out locally, globally or as a combination of both methods.
Harmonics detection and filtering
Harmonics in the network affect the quality of energy and are at the origin of many pollutions as overloads, vibrations, ageing of equipment, trouble of sensitive equipment, of local area networks, telephone networks. This chapter deals with the origins and the effects of harmonics and explain how to measure them and present the solutions.
Particular supply sources and loads
Particular items or equipment are studied: c Specific sources such as alternators or inverters c Specific loads with special characteristics, such as induction motors, lighting circuits or LV/LV transformers c Specific systems, such as direct-current networks
Domestic and similar premises and special locations
Certain premises and locations are subject to particularly strict regulations: the most common example being domestic dwellings. Prepared By: Zone4info.com Team Source: Internet
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Zone4info - Calculation of lighting requirements Part-1
Calculation of lighting requirements Part-1 Posted by Johan column May 21
Inverse-square law
If we were to illuminate a surface by means of a lamp positioned vertically above it, measure the illumination at the surface, and then move the lamp twice as far away, the illumination now measured would be four times less. If it were moved away three times the original distance of the illumination would be nine times less. Hence it will be seen that the illuminance on a surface is governed by the square of the vertical distance of the source from the surface ( Fig. 10.15 ).
Example A light source of 900 cd is situated 3 m above a working surface. (a) Calculate the illuminance directly below the source. (b) What would be the illuminance if the lamp were moved to a position 4 m from the surface?
Cosine rule From Fig. 10.16 it will be seen that point X is further from the source than is point Y. The illuminance at this point is therefore less. In fact the illuminance at X depends on the cosine of the angle q . Hence,
Example A 250 W sodium-vapour street lamp emits a light of 22 500 cd and is situated 5 m above the road. Calculate the illuminance (a) directly below the lamp and (b) at a horizontal distance along the road of 6 m ( Fig. 10.17 ). From Fig. 10.17 , it can be seen that the illuminance at A is given by
The illuminance at B is calculated as follows. Since the angle be found most simply by trigonometry:
is not known, it can
and from cosine tables:
In order to estimate the number and type of light fittings required to suit a particular environment, it is necessary to know what level of illuminance is required, the area to be illuminated, the MF and the CU, and the efficacy of the lamps to be used. Example A work area at bench level is to be illuminated to a value of 300 lx, using 85 W single fluorescent fittings having an efficacy of 80 lm/W. The work area is 10 m x 8 m, the MF is 0.8 and the CU is 0.6. Calculate the number of fittings required .
Source: Internet Contributed by: Zone4info.com Team
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Zone4info - Electrical Isolation procedure
Electrical Isolation procedure Posted by Mark David May 20
It is very important to ensure that the circuit that you want to isolate is live before you start. To check this, a voltage indicator/test lamp or a piece of equipment that is already connected to the circuit should be used. If it appears that the circuit is already dead, you need to know why. • Is somebody else working on it? • Is the circuit faulty? • Is it connected? • Has there been a power cut? You must make absolutely certain that you and you alone are in control of the circuit to be worked on. Providing the circuit is live you can proceed as follows: STEP 1
STEP 2 Test between all live conductors and live conductors and earth.
STEP 3 Locate the point of isolation. Isolate and lock off. Place warning notice (DANGER ELECTRICIAN AT WORK) at the point of isolation.
STEP 4 Test circuit to prove that it is the correct circuit that you have isolated.
Be careful! Most test lamps will trip an RCD when testing between live and earth, it is better to use an approved voltage indicator to GS 38 as most of these do not trip RCDs STEP 5 Check that the voltage indicator is working by testing it on a proving unit or a known live supply.
It is now safe to begin work. If the circuit which has been isolated is going to be disconnected at the consumerâ&#x20AC;&#x2122;s unit or distribution board, REMEMBER the distribution board should also be isolated. The Electricity at Work Regulations 1989 do not permit live working. When carrying out the safe isolation procedure never assume anything, always follow the same procedure Source: Internet, Installation of Electrical HandBook Contributed by: Zone4info.com Team
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Zone4info - Earthing System
Earthing System
Posted by Johan column May 20
Electrical system must have an earthed system, which means that the star or neutral point of the secondary side of distribution transformers is connected to the general mass of earth. In this way, the star point is maintained at or about 0 V. Unfortunately, this also means that persons or livestock in contact with a live part and earth are at risk of electric shock There are three main methods of earthing used in the United Kingdom, these are the TT system, the TN-S system, and the TN-C-S system. The letter T is the first letter of the French word for earth ‘terre ’, and indicates a direct contact to the general mass of earth. The letter N indicates that there is also the connection of a conductor to the star or neutral point of the supply transformer, which is continuous throughout the distribution system and terminates at the consumer’s intake position. The letters C and S mean ‘combined’ and ‘separate’, respectively. So a TT system has the star or neutral point of the supply transformer directly connected to earth by means of an earth electrode, and the earthing of the consumer’s installation is also directly connected to earth via an earth electrode ( Figure ). This system is typical of an overhead line supply in a rural area.
A TN-S system has the star point of the supply transformer connected to earth. Also the outer metallic sheaths of the distribution cable and, ultimately, the service cable are also connected to the star point. Hence, there are separate (S) metallic earth and neutral conductors throughout the whole system ( Figure 1.6 ). A TN-C-S system (also known as protective multiple earthing, PME) has the usual star connection to earth and the metallic sheaths of the distribution and service cables also connected to the star point. In this case, however, the outer cable sheath is also used as a neutral conductor (i.e. it is a combined (C) earth and neutral).
However, the system inside the consumerâ&#x20AC;&#x2122;s premises continues to have separate (S) earth and neutral conductors
These are the three main earthing systems used in the United Kingdom. They all rely on an earthed star point of the supply transformer and various methods of providing an earth path for fault currents. Source: Electric Wiring Design Author: zone4info.com Team
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Zone4info - Basic components of electric power cables
Basic components of electric power cables Posted by Zone 4info May 16
Figure 4.1 Generic representation of a electric power cable. The submarine power AC cables have an important role in offshore wind energy. Furthermore, the submarine cables are the main difference between the offshore wind farms transmission system and onshore wind farms transmission system. Therefore, a proper submarine cable model is crucial to perform accurate evaluations of the offshore wind farms collector and transmission systems. So, in the present chapter the different options to model a submarine cable are evaluated and their accuracy is discussed. Then based on an accurate and validated submarine cable model, an analysis about the reactive power management in submarine power transmission lines is carried out. Thus, taken into account active power losses, the reactive power generated in the transmission system and the voltage drop for three different reactive power management options, a reactive power compensation option is proposed. Basic components of electric power cables The purpose of a power cable is to carry electricity safely from the power source to different loads. In order to accomplish this goal, the cable is made up with some components or parts. Figure 4.1 shows a description of the cable components, which are: Conductor: The conductor is referred to the part or parts of the cable which carry the electric power. Electric cables can be made up by one conductor (mono-phase cables), three (threephase cables), four, etc. Insulation: Dielectric material layer with the purpose of insulate conductors of different phases or between phases and ground. Shield: metal coating, which covers the entire length of the cable. It is used to confine the electric field inside the cable and distribute uniformly this field. Armor or sheath: Layer of heavy duty material used to protect the components of the
cable for the external environment. Conductor Some materials, especially metals, have huge numbers of electrons that can move through the material freely. These materials have the capability to carry electricity from one object to another and are called conductors. Thus, conductor is called to the part or parts of the cable which carry electric power. The conductor may be solid or made up with various strands twisted together. The strand can be concentric, compressed, compacted, segmental, or annular to achieve desired properties of flexibility, diameter, and current density. The choice of the material as a conductor depends on: its electrical characteristics (capability to carry electricity), mechanical characteristics (resistance to wear, malleability), the specific use of the conductor and its cost. The classification of electric conductors depends on the way the conductor is made up. As a result, the conductors can be classified as Classification by construction characteristics Solid conductor: Conductor made up with only one conductor strand.
Figure 4.2 Conductor made up with Only one conductor strand. Strand conductor: Conductor made up with several low section strands twisted together. This kind of conductor has bigger flexibility than solid conductor.
Figure 4.3 Conductor made up with several low section strands twisted together. Classification by the number of conductors Mono-conductor: Conductor with only one conductive element, with insulation and with or without sheath.
Figure 4.4 Conductor with Only one conductive element. Multiple-conductor: Conductor with two or more conductive elements, with insulation and with one or more sheaths.
Figure 4.5 Conductor with multiple conductive elements. Insulation The purpose of the insulation is to prevent the electricity flow through it. So the insulation is used to avoid the conductor get in touch with people, other conductors with different voltages, objects, artifacts or other items. Air insulated conductors A metallic conductor suspended from insulating supports, surrounded by air, and carrying electric power may be considered as the simplest case of an insulated conductor Air is not a very good insulating material since it has lower voltage breakdown strength than many other insulating materials, but it is low in cost if space is not a constraint. On the contrary, if the space is a constraint, the air is replaced as insulation material for another material with higher voltage breakdown strength . The same occurs in environments where isolation by air is not possible like submarine cables. In this case neither is possible isolation by sea water, since it is not an insulating material.
Air insulated conductor. Insulation by covering the conductor with a dielectric material In this type of insulation, the conductor is covered by an insulating material with high voltage breakdown strength (a dielectric), usually a polymer.
If the metallic conductor is covered with an insulating material, transmission lines can be placed close to ground or touching the ground. But in this cases when the ground plane is brought close or touches the covering, the electric field lines become increasingly distorted. Considering the equipotential lines of the electric field, these are bended due to the potential difference on the covering surface. As shown At low voltages, the effect is negligible. As the voltage increases, the point is reached where the potential gradients are enough to cause current to flow across the surface of the covering. This is commonly known as â&#x20AC;&#x153;tracking.â&#x20AC;? Even though the currents are small, the high surface resistance causes heating to take place which ultimately damages the covering. If this condition is allowed to continue, eventually the erosion may progress to failure
Equipotential lines of the conductorâ&#x20AC;&#x2122;s electric field when the transmission line is close to the ground. Therefore, high voltage power cables close to ground, like submarine cables, are provided with a shield to avoid this effect. Source: Energy Transmission and Grid Integration of AC Author: zone4info.com Team
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Zone4info - Electrical Installations
Electrical Installations Posted by Johan column May 20
THE MAIN INTAKE POSITION
Unless domestic premises are extremely large, it is unlikely that a three-phase supply would be needed, and consequently only single-phase systems will be considered here. Figures 2.1, 2.2 and 2.3 illustrate the typical intake arrangements for TT, TN-S and TN-C-S systems. Although many TT installations are protected by one single 30 mA residual current device (RCD) (as shown in Figure ), this does not conform to the IEE Regulations regarding ‘installation circuit arrangement ’.
The requirement is that circuits which need to be separately controlled, for example lighting and power, remain energized in the event of the failure of any other circuit of the installation. Hence, an earth fault on, say, a socket-outlet circuit would cause the whole of the installation to be cut off if protected by one 30 mA RCD. One preferred arrangement is to protect the whole installation by a 100 mA RCD and, using a ‘splitload’ consumer unit, protect the socket-outlet circuits with a 30 mA RCD
Alternatively, combined RCD/CB devices (RCBOs) may be used to protect each circuit individually ( Figure ). In many domestic situations, â&#x20AC;&#x2DC;off-peak â&#x20AC;&#x2122; electricity is used, as this can be a means of reducing electricity bills. Energy is consumed out of normal hours, for example 11.00 pm to 7.00 am, and the tariff (the charge per unit of energy used) is a lot less. This arrangement lends itself to the use of storage heaters and water heating, and the supply intake equipment will incorporate
special metering arrangements. The DNOs have their own variations on a common theme, depending on consumerâ&#x20AC;&#x2122;s requirements, but, typically, the supply from the cutout (this houses the DNOs fuse and neutral) feeds a digital meter from which three consumer units are fed: one for normal use, one for storage heating and one for water heating ( Figure 2.4 ).
In these cases, these meters or telemeters, as they are known, are switched on and off by radio signals activated from the DNOs centre. In the case of water heating, there is normally a ‘midday boost ’ for about 2 hours. In most DNO areas, electricity used during the night by normal circuits, that is lighting and power, attracts a lower tariff. As a result, it is cost-effective to carry out washing and drying activities during this nighttime period. Many older installations incorporate the ‘white meter ’ arrangement which uses a separate meter to register energy used during off-peak periods. Although most new installations are based around the telemetering system, older metering installations are still valid. They are all variations on the same theme, that is they use electricity outside normal hours and the charge per unit will be less.
Source: Electrical design Hand Books Author: Zone4info.com Team