Power system operations and control

Hours-ahead operation

In the hours prior to the delivery, a system operator might need to deploy additional supplemental reserves or even commit more generation units, primarily to ensure the reliability of the supply while still trying to minimize the costs. At the same time, operator must ensure that enough reactive power reserves are available to prevent a voltage collapse.

Dispatch curve

The decisions ("economic dispatch") are based on the dispatch curve, where the X-axis constitutes the system power, intervals for the generation units are placed on this axis in the merit order with the interval length corresponding to the maximum power of the unit, Y-axis values represent the marginal cost (per-MWh of electricity, ignoring the startup costs). For cost-based decisions, the units in the merit order are sorted by the increasing marginal cost. The graph on the right describes an extremely simplified system, with three committed generator units (fully dispatchable, with constant per-MWh cost):

• unit A can deliver up to 120 MW at the cost of $30 per MWh (from 0 to 120 MW of system power);
• unit B can deliver up to 80 MW at $60/MWh (from 120 to 200 MW of system power);
• unit C is capable of 50 MW at $120/MWh (from 200 to 250 MW of system power).

At the expected demand is 150 MW (a vertical line on the graph), unit A will be engaged at full 120 MW power, unit B will run at the dispatch level of 30 MW, unit C will be kept in reserve. The area under the dispatch curve to the left of this line represents the cost per hour of operation (ignoring the startup costs, $30 * 120 + $60 * 30 = $5,400 per hour), the incremental cost of the next MWh of electricity ($60 in the example, represented by a horizontal line on the graph) is called system lambda (thus another name for the curve, system lambda curve).

In real systems the cost per MWh usually is not constant, and the lines of the dispatch curve are therefore not horizontal (typically the marginal cost of power increases with the dispatch level, although for the combined cycle power plants there are multiple cost curves depending on the mode of operation, so the power-cost relationship is not necessarily monotonic).

If the minimum level of demand in the example will stay above 120 MW, the unit A will constantly run at full power, providing baseload power, unit B will operate at variable power, and unit C will need to be turned on and off, providing the "intermediate" or "cycling" capacity. If the demand goes above 200 MW only occasionally, the unit C will be idle most of the time and will be considered a peaking power plant (a "peaker"). Since a peaker might run for just tens of hours per year, the cost of peaker-produced electricity can be very high in order to recover the capital investment and fixed costs (see the right side of a hypothetical full-scale dispatch curve).

Redispatch

Sometimes the grid constraints change unpredictably and a need arises to change the previously set unit commitments. This system redispatch change is controlled in real-time by the central operator issuing directives to market participants that submit in advance bids for the increase/decrease in the power levels. Due to the centralized nature of redispatch, there is no delay in negotiating the terms of the contracts; the costs incurred are allocated either to participants responsible for the disruption based on preestablished tariffs or in equal shares.

Minutes-ahead operation

In the minutes prior to the delivery, a system operator is using the power-flow study algorithms in order to find the optimal power flow. At this stage the goal is reliability ("security") of the supply, applying contingency analysis. The practical electric networks are too complex to perform the calculations by hand, so from the 1920s the calculations were automated, at first in the form of specially-built analog computers, so called network analyzers, replaced by digital computers in the 1960s.

Control after disturbance

Small mismatches between the total demand and total load are typical and initially are taken care of by the kinetic energy of the rotating machinery (mostly synchronous generators): when there is too little demand, the devices absorb the excess, and frequency goes above the scheduled rate, conversely, too much demand causes the generator to deliver extra electricity through slowing down, with frequency slightly decreasing, not requiring an intervention from the operator. There are obvious limits to this "immediate control", so a control continuum is built into a typical power grid, spanning reaction intervals from seconds ("primary control") to hours ("time control").

Seconds-after control

The primary control is engaged automatically within seconds after a frequency disturbance. Primary control stabilizes the situation, but does not return the conditions to normal and is applied both to the generation side (where the governor adjusts the power of the prime mover) and to the load, where:

• induction motors self-adjust (lower frequency reduces the energy use);
• under-frequency relays disconnect interruptible loads;
• ancillary services are engaged (load is reduced as procured via reliability services contracts).

Another term commonly used for the primary control is frequency response (or "beta"). Frequency response also includes the inertial response of the generators. This is the parameter that is approximated by the frequency bias coefficient of the area control error (ACE) calculation used for automatic generation control.

Minutes-after control

The secondary control is used to restore the system frequency after a disturbance, with adjustments made by the balancing authority control computer (this is typically referred to as load-frequency control or automatic generation control) and manual actions taken by the balancing authority staff. Secondary control uses both the spinning and non-spinning reserves, with balancing services deployed within minutes after a disturbance (hydropower plants are capable of an even faster reaction).

Tertiary control

The tertiary control involves reserve deployment and restoration to handle the current and future contingencies.

Emergency control

In the event of a significant grid contingency, like a major loss of generation capacity, emergency measures might be necessary to avoid a cascading failure. Load shedding (LS) is a standard emergency control action that reduces demand by disconnecting certain loads within an acceptable timeframe (0.2 – 3 seconds), thereby preventing the collapse of the grid. Another emergecy control action is islanding.

Time control

The goal of the time control is to maintain the long-term frequency at the specified value within a wide area synchronous grid. Due to the disturbances, the average frequency drifts, and a time error accumulates between the official time and the time measured in the AC cycles. In the US, the average 60 Hz frequency is maintained within each interconnection by a designated entity, time monitor, that periodically changes the frequency target of the grid (scheduled frequency) to bring the overall time offset within the predefined limits. For example, in the Eastern Interconnection the action (temporarily setting the frequency to 60.02 Hz or 59.98 Hz) is initiated when the time offset reaches 10 seconds and ceases once the offset reaches 6 seconds. Time control is performed either by a computer (Automatic Time Error Correction), or by the monitor requesting balancing authorities to adjust their settings.