Power system operations and control

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Power system operations is a term used in electricity generation to describe the process of decision-making on the timescale from one day (day-ahead operation [1] ) to minutes [2] prior to the power delivery. The term power system control describes actions taken in response to unplanned disturbances (e.g., changes in demand or equipment failures) in order to provide reliable electric supply of acceptable quality. [3] The corresponding engineering branch is called Power System Operations and Control. Electricity is hard to store, so at any moment the supply (generation) shall be balanced with demand ("grid balancing"). In an electrical grid the task of real-time balancing is performed by a regional-based control center, run by an electric utility in the traditional (vertically integrated) electricity market. In the restructured North American power transmission grid, these centers belong to balancing authorities numbered 74 in 2016, [4] the entities responsible for operations are also called independent system operators, transmission system operators. The other form of balancing resources of multiple power plants is a power pool. [5] The balancing authorities are overseen by reliability coordinators. [6]

Contents

Day-ahead operation

Day-ahead operation schedules the generation units that can be called upon to provide the electricity on the next day (unit commitment). The dispatchable generation units can produce electricity on demand and thus can be scheduled with accuracy. The production of the weather-dependent variable renewable energy for the next day is not certain, its sources are thus non-dispatchable. This variability, coupled with uncertain future power demand and the need to accommodate possible generation and transmission failures requires scheduling of operating reserves that are not expected to produce electricity, but can be dispatched on a very short notice. [1]

Some units have unique features that require their commitment much earlier: for example, the nuclear power stations take a very long time to start, while hydroelectric plants require planning of water resources usage way in advance, therefore commitment decisions for these are made weeks or even months before prior to the delivery. [7]

For a "traditional" vertically integrated electric utility the main goal of the unit commitment is to minimize both the marginal cost of producing the unit electricity and the (quite significant for fossil fuel generation) start-up costs. In a "restructured" electricity market a market clearing algorithm is utilized, frequently in a form of an auction; the merit order is sometimes defined not just by the monetary costs, but also by the environmental concerns. [1]

Unit commitment is more complex than the shorter-time-frame operations, since unit availability is subject to multiple constraints: [8]

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 the voltage collapse. [2]

Dispatch curve

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): [7]

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). [10]

Hypothetical dispatch curve (USA, summer 2011) Hypothetical dispatch curve, USA, Summer 2011.png
Hypothetical dispatch curve (USA, summer 2011)

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 to negotiate terms of contracts; the cost incurred are allocated either to participants responsible for the disruption based on preestablished tariffs or in equal shares. [12]

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. [2] 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 much supply, 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, [13] 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"). [14]

Seconds-after control

The primary control is engaged automatically within seconds after the frequency disturbance. Primary control stabilizes the situation, but does not return the conditions to the normal and is applied both to the generation side (where the governor adjusts the power of the prime mover) and to the load, where: [15]

Another term commonly used for the primary control is frequency response (or "beta"). Frequency response also includes the inertial response of the generators. [16] This is the parameter that is approximated by the frequency bias coefficient of the area control error (ACE) calculation used for automatic generation control. [17]

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 disturbance (hydropower plants are capable of an even faster reaction). [18]

Tertiary control

The tertiary control involves reserve deployment and restoration to handle the current and future contingencies. [19]

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 [13] ) 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. [20]

Related Research Articles

In a broad sense, an electricity market is a system that facilitates the exchange of electricity-related goods and services. During more than a century of evolution of the electric power industry, the economics of the electricity markets had undergone enormous changes for reasons ranging from the technological advances on supply and demand sides to politics and ideology. A restructuring of electric power industry at the turn of the 21st century involved replacing the vertically integrated and tightly regulated "traditional" electricity market with multiple competitive markets for electricity generation, transmission, distribution, and retailing. The traditional and competitive market approaches loosely correspond to two visions of industry: the deregulation was transforming electricity from a public service into a tradable good. As of 2020s, the traditional markets are still common in some regions, including large parts of the United States and Canada.

Distributed generation, also distributed energy, on-site generation (OSG), or district/decentralized energy, is electrical generation and storage performed by a variety of small, grid-connected or distribution system-connected devices referred to as distributed energy resources (DER).

<span class="mw-page-title-main">Utility frequency</span> Frequency used on standard electricity grid in a given area

The utility frequency, (power) line frequency or mains frequency is the nominal frequency of the oscillations of alternating current (AC) in a wide area synchronous grid transmitted from a power station to the end-user. In large parts of the world this is 50 Hz, although in the Americas and parts of Asia it is typically 60 Hz. Current usage by country or region is given in the list of mains electricity by country.

<span class="mw-page-title-main">National Grid (Great Britain)</span> High-voltage electric power transmission network in Great Britain

The National Grid is the high-voltage electric power transmission network serving Great Britain, connecting power stations and major substations, and ensuring that electricity generated anywhere on the grid can be used to satisfy demand elsewhere. The network serves the majority of Great Britain and some of the surrounding islands. It does not cover Northern Ireland, which is part of the Irish single electricity market.

The National Electricity Market (NEM) is an arrangement in Australia's electricity sector for the connection of the electricity transmission grids of the eastern and southern Australia states and territories to create a cross-state wholesale electricity market. The Australian Energy Market Commission develops and maintains the Australian National Electricity Rules (NER), which have the force of law in the states and territories participating in NEM. The Rules are enforced by the Australian Energy Regulator. The day-to-day management of NEM is performed by the Australian Energy Market Operator.

<span class="mw-page-title-main">Electric Reliability Council of Texas</span> Regional transmission organization in Texas

The Electric Reliability Council of Texas, Inc. (ERCOT) is an American organization that operates Texas's electrical grid, the Texas Interconnection, which supplies power to more than 25 million Texas customers and represents 90 percent of the state's electric load. ERCOT is the first independent system operator (ISO) in the United States. ERCOT works with the Texas Reliability Entity (TRE), one of eight regional entities within the North American Electric Reliability Corporation (NERC) that coordinate to improve reliability of the bulk power grid.

<span class="mw-page-title-main">Demand response</span> Techniques used to prevent power networks from being overwhelmed

Demand response is a change in the power consumption of an electric utility customer to better match the demand for power with the supply. Until the 21st century decrease in the cost of pumped storage and batteries electric energy could not be easily stored, so utilities have traditionally matched demand and supply by throttling the production rate of their power plants, taking generating units on or off line, or importing power from other utilities. There are limits to what can be achieved on the supply side, because some generating units can take a long time to come up to full power, some units may be very expensive to operate, and demand can at times be greater than the capacity of all the available power plants put together. Demand response, a type of energy demand management, seeks to adjust in real-time the demand for power instead of adjusting the supply.

<span class="mw-page-title-main">Texas Interconnection</span> Power grid providing power to most of Texas

The Texas Interconnection is an alternating current (AC) power grid – a wide area synchronous grid – that covers most of the state of Texas. The grid is managed by the Electric Reliability Council of Texas (ERCOT).

A virtual power plant (VPP) is a cloud-based distributed power plant that aggregates the capacities of heterogeneous distributed energy resources (DER) for the purposes of enhancing power generation, trading or selling power on the electricity market, and demand side options for load reduction.

To balance the supply and demand of electricity on short timescales, the UK National Grid has contracts in place with generators and large energy users to provide temporary extra power, or reduction in demand. These reserve services are needed if a power station fails for example, or if forecast demand differs from actual demand. National Grid has several classes of reserve services, which in descending order of response time are: Balancing Mechanism (BM) Start-Up, Short-Term Operating Reserve, Demand Management and Fast Reserve.

<span class="mw-page-title-main">Load management</span> Process of balancing the supply of electricity on a network

Load management, also known as demand-side management (DSM), is the process of balancing the supply of electricity on the network with the electrical load by adjusting or controlling the load rather than the power station output. This can be achieved by direct intervention of the utility in real time, by the use of frequency sensitive relays triggering the circuit breakers, by time clocks, or by using special tariffs to influence consumer behavior. Load management allows utilities to reduce demand for electricity during peak usage times, which can, in turn, reduce costs by eliminating the need for peaking power plants. In addition, some peaking power plants can take more than an hour to bring on-line which makes load management even more critical should a plant go off-line unexpectedly for example. Load management can also help reduce harmful emissions, since peaking plants or backup generators are often dirtier and less efficient than base load power plants. New load-management technologies are constantly under development — both by private industry and public entities.

<span class="mw-page-title-main">Availability-based tariff</span> Pricing system used in India for unscheduled electric power transactions

Availability Based Tariff (ABT) is a frequency based pricing mechanism applicable in India for unscheduled electric power transactions. The ABT falls under electricity market mechanisms to charge and regulate power to achieve short term and long term network stability as well as incentives and dis-incentives to grid participants against deviations in committed supplies as the case may be.

<span class="mw-page-title-main">Electrical grid</span> Interconnected network for delivering electricity from suppliers to consumers

An electrical grid is an interconnected network for electricity delivery from producers to consumers. Electrical grids vary in size and can cover whole countries or continents. It consists of:

Ancillary services are the services necessary to support the transmission of electric power from generators to consumers given the obligations of control areas and transmission utilities within those control areas to maintain reliable operations of the interconnected transmission system.

Inertial response is a property of large synchronous generators, which contain large synchronous rotating masses, and which acts to overcome any immediate imbalance between power supply and demand for electric power systems, typically the electrical grid. Due to the ever existing power imbalance between mechanical power supply and electric power demand the rotational frequency of the rotating masses in all synchronous generators in the grid either speed up and thus absorb the extra power in case of an excess power supply, or slow down and provide additional power in case of an excess power demand. This response in case of a synchronous generator is built-in into the design and happens without any external intervention or coordination, providing the automatic generation control and the grid operator with valuable time to rebalance the system The grid frequency is the combined result of the detailed motions of all individual synchronous rotors in the grid, which are modeled by a general equation of motion called the swing equation.

Grid balancing ensures that electricity consumption matches electricity production of an electrical grid at any moment. Electricity is by its nature difficult to store and has to be available on demand, so the supply shall match the demand very closely at any time despite the continuous variations of both. In a deregulated grid, a transmission system operator is responsible for the balancing. In a wide area synchronous grid the short-term balancing is coupled with frequency control: as long as the balance is maintained, the frequency stays constant, whenever a small mismatch between aggregate demand and aggregate supply occurs, it is restored due to both supply and demand being frequency-sensitive: lower frequency increases the supply, and higher frequency increases the demand.

<span class="mw-page-title-main">North American power transmission grid</span> Series of electrical grids that power the US and Canada

The electrical power grid that powers Northern America is not a single grid, but is instead divided into multiple wide area synchronous grids. The Eastern Interconnection and the Western Interconnection are the largest. Three other regions include the Texas Interconnection, the Quebec Interconnection, and the Alaska Interconnection. Each region delivers power at a nominal 60 Hz frequency. The regions are not usually directly connected or synchronized to each other, but there exist some HVDC interconnectors. The Eastern and Western grids are connected with 1.32 GW.

Wreck Cove is the largest hydroelectric system in Nova Scotia with a generating capacity of 215.8 MW. Constructed from 1975 to 1978, south of the Cape Breton Highlands National Park, Wreck Cove collects drainage water from 216 square kilometres (83 sq mi) of the Cape Breton Highlands plateau to generate renewable electricity. It consists of two generating stations: the Gisborne Generating Station, with an installed capacity of 3.5 MW, and the Wreck Cove Generating Station, with an installed capacity of 212 MW, producing on average 318 GWh annually—enough energy to power about 30,000 homes.

A balancing authority (BA) is an entity in the US electric system that is responsible for grid balancing: resource planning and unit commitment ahead of time, maintenance of the load-interchange-generation balance within a balancing authority area and support for real-time load-frequency control. The balancing authorities are connected by metered high-voltage tie lines and grouped into interconnections:

Resource adequacy in the field of electric power is the ability of the electric grid to satisfy the end-user power demand at any time. RA is a component of the electric system reliability. For example, sufficient unused generation capacity shall be available to the electrical grid at any time to accommodate equipment failures and drops in variable renewable energy sources. The adequacy standard should satisfy the chosen reliability index, typically the loss of load expectation (LOLE) of 1 day in 10 years.

References

  1. 1 2 3 Conejo & Baringo 2017, p. 9.
  2. 1 2 3 Conejo & Baringo 2017, p. 10.
  3. ↑ S. Sivanagaraju (2009). Power System Operation and Control. Pearson Education India. pp. 557–. ISBN   9788131726624. OCLC   1110238687.
  4. ↑ "U.S. electric system is made up of interconnections and balancing authorities". eia.gov. United States Energy Information Administration. 20 July 2016. Retrieved 31 May 2022.
  5. ↑ Bhattacharya, Bollen & Daalder 2012, pp. 54.
  6. ↑ NERC 2018, p. 8.
  7. 1 2 "Economic Dispatch and Operations of Electric Utilities". psu.edu. EME 801 Energy Markets, Policy, and Regulation: Penn State University.{{cite web}}: CS1 maint: location (link)
  8. ↑ Bhattacharya, Bollen & Daalder 2012, pp. 47–52.
  9. ↑ Wood & Wollenberg 1984, p. 117.
  10. ↑ Bayón, L.; García Nieto, P. J.; Grau, J. M.; Ruiz, M. M.; Suárez, P. M. (19 March 2013). "An economic dispatch algorithm of combined cycle units" (PDF). International Journal of Computer Mathematics. 91 (2): 269–277. doi:10.1080/00207160.2013.770482. eISSN   1029-0265. ISSN   0020-7160. S2CID   5930756.
  11. ↑ "Electric generator dispatch depends on system demand and the relative cost of operation". eia.gov. 17 August 2012. Retrieved 30 May 2022.
  12. ↑ Yong-Hua Song (31 July 2003). "System Redispatch". In Yong-Hua Song; Xi-Fan Wang (eds.). Operation of Market-oriented Power Systems. Springer Science & Business Media. p. 150. ISBN   978-1-85233-670-7. OCLC   1112226019.
  13. 1 2 NERC 2021, p. 1.
  14. ↑ NERC 2021, p. 6.
  15. ↑ NERC 2021, p. 13.
  16. ↑ NERC 2021, p. 12.
  17. ↑ NERC 2021, p. 14.
  18. ↑ NERC 2011, pp. 12–13.
  19. ↑ NERC 2011, p. 13.
  20. ↑ NERC 2011, pp. 13–14.

Sources

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