Load Shedding

Load shedding is what electric utilities do when there is a huge demand for electricity that exceeds the generation available. The alternative is to have a brown-out where the voltage is reduced. 

It costs a lot to have generators standing by just in case there is a surge of demand, and the operators of those generators expect to be paid whether they run the generators or not. An alternative is if there is a large consumer of electricity (say, a factory) that could suddenly turn off all its electricity demand, they could agree to do that on request, and it has the same benefit as adding that amount of generation to the electric grid. In fact, it's better -- as there is less demand on the wires which are often saturated at the same time. 

That factory has losses from shutting down its equipment and idling its workers, but if the money it gets paid is enough, then it's worth it. This is an example of load shedding. 

There are many other cases where lots of smaller consumers agree to reduce demand on hot summer days, such as by reducing air conditioning or lighting. 

Someone who aggregates all these smaller cases can have the same effect as one big generator and so get the same money, and the operators of the electric grid are happy as it effectively solves the peak demand problem. 

When there is a shortfall in the electricity supply, there can be a need to reduce demand very quickly to an acceptable level, or risk the entire electricity network becoming unstable and shutting down completely. This is known as a “cascade” event, and can end in a total or widespread network shutdown affecting very large areas of a country. Some recent examples include the blackouts in northeast America and Canada in 2003 and across Italy in the same year and in India in 2012.

As the system frequency approaches the normal 60 Hz or 50 Hz ,a frequency relay can be used to automatically begin the restoration of the load that has been shed. The amount of load that can be restored  is determined by  the ability of the system to serve it .The criteria is that   the available generation must  always exceed  the amount  of  load being restored so that the system frequency will continue to recover . Any serious decrease in system frequency at this point could lead to undesirable load shedding repetition, which could start a system oscillation between shedding and restoration. This would be a highly undesirable condition. The availability of generation, either locally or through system interconnections ,   determines whether or not the shed load can be successfully restored.

Therefore, a load restoration program usually incorporates time delay, which is related to the amount of time required to add generation or to close tie- lines during emergency conditions. Also, both the time delay and the restoration frequency set points should be staggered so that all of the load is not   reconnected at the same time.  Reconnecting loads on a distributed basis also minimizes power swings across the system and thereby minimizes the possibility of initiating a new disturbance.

The drop in frequency may endanger generation itself .While a hydro-electric plant is   relatively unaffected by even a  ten percent  reduction in frequency, a thermal generating plant is quite sensitive  to even a five percent reduction.  Power output of a thermal plant depends to a great extent  on  its motor driven auxiliaries such as boiler feed water pumps, coal pulverizing and feeding equipment, and draft fans. As system frequency decreases, the power output to the auxiliaries begins to fall off rapidly which in

turn further reduces the energy input to the turbine generator. The situation thus has a cascading effect with a  loss of frequency leading to a loss of power which can cause the frequency to deteriorate further and the entire plant is soon in serious trouble. An additional major concern is the possible damage to the steam  turbines due  to prolonged operation at reduced frequency during this severe overload

condition .

Load shedding normally happens in two ways:

Automatic Load Shedding

This is a result of concurrent failures of major element(s) in the national grid (e.g.co-incidental generator or key transmission line failures), resulting in protection schemes initiating the automatic isolation of additional parts of the national grid, to protect the entire grid from cascading to a total blackout. Automatic load shedding always occurs on the transmission system level, with the result being large

amounts of electricity and large blocks of customers taken off supply in a very short time. Typical load reduction amounts can be in the order of 1000MW – 2000MW, affecting hundreds of thousands of customers.

Manual (Selective) Load Shedding

This occurs where time is available (typically up to 30mins) to make selective choices on what customers are shed. Selective load shedding often occurs on the distribution system level, and typically requires medium to small amounts of electricity to be “shed” in a short time (rolling blackout). Typical load reduction amounts can be in the order of 50MW – 100MW, affecting tens of thousands of customers at a time. 

In order to minimise the impact on individual customers and share the burden, rotational load shedding (rolling blckout) will occur on the low priority feeders if the load shedding duration extends for several hours. Typically the first group of customers who were shed will be restored after one or two hours, at the expense of the next group of customers to be taken off supply. This can continue until the supply/demand equation is balanced again and load shedding is no longer required.

Magnetic Inrush

When a transformer is initially connected to a source of AC voltage, there may be a substantial surge of current through the primary winding called inrush current.

We know that the rate of change of instantaneous flux in a transformer core is proportional to the instantaneous voltage drop across the primary winding. Or, as stated before, the voltage waveform is the derivative of the flux waveform, and the flux waveform is the integral of the voltage waveform. In a continuously-operating transformer, these two waveforms are phase-shifted by 90^o. Since flux (Φ) is proportional to the magnetomotive force (mmf) in the core, and the mmf is proportional to winding current, the current waveform will be in-phase with the flux waveform, and both will be lagging the voltage waveform by 90^o 

Let us suppose that the primary winding of a transformer is suddenly connected to an AC voltage source at the exact moment in time when the instantaneous voltage is at its positive peak value. In order for the transformer to create an opposing voltage drop to balance against this applied source voltage, a magnetic flux of rapidly increasing value must be generated. The result is that winding current increases rapidly, but actually no more rapidly than under normal conditions. Both core flux and coil current start from zero and build up to the same peak values experienced during continuous operation. Thus, there is no "surge" or "inrush" or current in this scenario.

Alternatively, let us consider what happens if the transformer's connection to the AC voltage source occurs at the exact moment in time when the instantaneous voltage is at zero. During continuous operation (when the transformer has been powered for quite some time), this is the point in time where both flux and winding current are at their negative peaks, experiencing zero rate-of-change (dΦ/dt = 0 and di/dt = 0). As the voltage builds to its positive peak, the flux and current waveforms build to their maximum positive rates-of-change, and on upward to their positive peaks as the voltage descends to a level of zero.

In an ideal transformer, the magnetizing current would rise to approximately twice its normal peak value as well, generating the necessary mmf to create this higher-than-normal flux. However, most transformers aren't designed with enough of a margin between normal flux peaks and the saturation limits to avoid saturating in a condition like this, and so the core will almost certainly saturate during this first half-cycle of voltage. During saturation, disproportionate amounts of mmf are needed to generate magnetic flux. This means that winding current, which creates the mmf to cause flux in the core, will disproportionately rise to a value easily exceeding twice its normal peak:

This is the mechanism causing inrush current in a transformer's primary winding when connected to an AC voltage source. As you can see, the magnitude of the inrush current strongly depends on the exact time that electrical connection to the source is made. If the transformer happens to have some residual magnetism in its core at the moment of connection to the source, the inrush could be even more severe. Because of this, transformer overcurrent protection devices are usually of the "slow-acting" variety, so as to tolerate current surges such as this without opening the circuit.

Surge Impedance Loading

The surge impedance loading or SIL of a transmission line is the MW loading of a transmission line at which a natural reactive power balance occurs.  

Transmission lines produce reactive power (Mvar) due to their natural capacitance. The amount of Mvar produced is dependent on the transmission line's capacitive reactance (XC) and the voltage (kV) at which the line is energized.  In equation form the Mvar produced is:  

                                                         

Transmission lines also utilize reactive power to support their magnetic fields (inductive).  The magnetic field strength is dependent on the magnitude of the current flow in the line and the line's natural inductive reactance (XL).  It follows then that the amount of Mvar used by a transmission line is a function of the current flow and inductive reactance.  In equation form the Mvar used by a transmission line is:

  

A transmission line's surge impedance loading or SIL is simply the MW loading (at a unity power factor) at which the line's Mvar usage is equal to the line's Mvar production.  In equation form we can state that the SIL occurs when:  

If we take the square root of both sides of the above equation and then substitute in the formulas for XL (=2pfL) and XC (=1/2pfC) we arrive at:  

The term     in the above equation is by definition the "surge impedance.  The theoretical

significance of the surge impedance is that if a purely resistive load that is equal to the surge impedance were connected to the end of a transmission line with no resistance, a voltage surge introduced to the sending end of the line would be absorbed completely at the receiving end.  The voltage at the receiving end would have the same magnitude as the sending end voltage and would have a phase angle that is lagging with respect to the sending end by an amount equal to the time required to travel across the line from sending to receiving end.

The value of the SIL to a system operator is realizing that when a line is loaded above its SIL it acts like a shunt reactor - absorbing Mvar from the system - and when a line is loaded below its SIL it acts like a shunt capacitor - supplying Mvar to the system.

Frequency

The primary reason for accurate frequency control is to allow the flow of alternating current power from multiple generators through the network to be controlled. The trend in system frequency is a measure of mismatch between demand and generation, and so is a necessary parameter for load control in interconnected systems.

Frequency of the system will vary as load and generation change. Increasing the mechanical input power to a synchronous generator will not greatly affect the system frequency but will produce more electric power from that unit. During a severe overload caused by tripping or failure of generators or transmission lines the power system frequency will decline, due to an imbalance of load versus generation. Loss of an interconnection, while exporting power (relative to system total generation) will cause system frequency to rise. Automatic generation control (AGC) is used to maintain scheduled frequency and interchange power flows. Control systems in power plants detect changes in the network-wide frequency and adjust mechanical power input to generators back to their target frequency. This counteracting usually takes a few tens of seconds due to the large rotating masses involved. Temporary frequency changes are an unavoidable consequence of changing demand. Exceptional or rapidly changing mains frequency is often a sign that an electricity distribution network is operating near its capacity limits, dramatic examples of which can sometimes be observed shortly before major outages.

Frequency protective relays on the power system network sense the decline of frequency and automatically initiate load shedding or tripping of interconnection lines, to preserve the operation of at least part of the network. Small frequency deviations (i.e.- 0.5 Hz on a 50 Hz or 60 Hz network) will result in automatic load shedding or other control actions to restore system frequency.

Smaller power systems, not extensively interconnected with many generators and loads, will not maintain frequency with the same degree of accuracy. Where system frequency is not tightly regulated during heavy load periods, the system operators may allow system frequency to rise during periods of light load, to maintain a daily average frequency of acceptable accuracy.

Frequency affects the power system in following ways;

 

Lighting

The first applications of commercial electric power were incandescent lighting  (normal bulb) and commutator-type electric motors. Both devices operate well on DC, but DC could not be easily changed in voltage, and was generally only produced at the required utilization voltage.

If an incandescent lamp is operated on a low-frequency current, the filament cools on each half-cycle of the alternating current, leading to perceptible change in brightness and flicker of the lamps.

Rotating machines

Commutator-type motors do not operate well on high-frequency AC because the rapid changes of current are opposed by the inductance of the motor field; even today, although commutator-type universal motors are common in 50 Hz and 60 Hz household appliances, they are small motors, less than 1 kW. The induction motor was found to work well on frequencies around 50 to 60 Hz but with the materials available in the 1890s would not work well at a frequency of, say, 133 Hz. There is a fixed relationship between the number of magnetic poles in the induction motor field, the frequency of the alternating current, and the rotation speed; so, a given standard speed limits the choice of frequency (and the reverse). Once AC electric motors became common, it was important to standardize frequency for compatibility with the customer's equipment.

Generators operated by slow-speed reciprocating engines will produce lower frequencies, for a given number of poles, than those operated by, for example, a high-speed steam turbine. For very slow prime mover speeds, it would be costly to build a generator with enough poles to provide a high AC frequency. As well, synchronizing two generators to the same speed was found to be easier at lower speeds. While belt drives were common as a way to increase speed of slow engines, in very large ratings (thousands of kilowatts) these were expensive, inefficient and unreliable.

Transmission and transformers

With AC, transformers can be used to step down high transmission voltages to lower customer utilization voltage. The transformer is effectively a voltage conversion device with no moving parts and requiring little maintenance. The use of AC eliminated the need for spinning DC voltage conversion motor-generators that require regular maintenance and monitoring.

Since, for a given power level, the dimensions of a transformer are roughly inversely proportional to frequency, a system with many transformers would be more economical at a higher frequency.

Electric power transmission over long lines favors lower frequencies. The effects of the distributed capacitance and inductance of the line are less at low frequency.

 

System interconnection

Generators can only be interconnected to operate in parallel if they are of the same frequency and wave-shape. By standardizing the frequency used, generators in a geographic area can be interconnected in a grid, providing reliability and cost savings.