Content deleted Content added
m →Seconds-after control: style |
→Minutes-ahead operation: Expanding article |
||
| (37 intermediate revisions by 5 users not shown) | |||
Line 1:
{{Short description|Power plant operation}}
'''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'''{{sfn|Conejo|Baringo|2017|p=9}}) to minutes{{sfn|Conejo|Baringo|2017|p=10}} 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.<ref name="Sivanagaraju2009">{{cite book | author = S. Sivanagaraju | date = 2009 | title = Power System Operation and Control | publisher = Pearson Education India | pages = 557– | isbn = 9788131726624 | oclc = 1110238687 | url = https://books.google.com/books?id=9GkhHYorvDAC&pg=PA557}}</ref> 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 ([[vertical integration#Electric utilities|vertically integrated]]) electricity market. In the restructured [[North American power transmission grid]], these centers belong to ''[[balancing authority|balancing authorities]]'' numbered 74 in 2016,<ref>{{cite web |title=U.S. electric system is made up of interconnections and balancing authorities |url=https://www.eia.gov/todayinenergy/detail.php?id=27152 |website=eia.gov |publisher=[[United States Energy Information Administration]] |access-date=31 May 2022 |date=20 July 2016}}</ref> the entities responsible for operations are also called [[independent system operator]]s, [[transmission system
== Day-ahead operation ==
Line 7:
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 [[electricity transmission|transmission]] failures requires scheduling of [[operating reserve]]s that are not expected to produce electricity, but can be dispatched on a very short notice.{{sfn|Conejo|Baringo|2017|p=9}}
Some units have unique features that require their commitment much earlier: for example, the [[nuclear power station]]s 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.<ref name=psu>{{cite web
For a "traditional" [[vertical integration#Electric utilities|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.{{sfn|Conejo|Baringo|2017|p=9}}
Unit commitment is more complex than the shorter-time-frame operations, since unit availability is subject to multiple constraints:{{sfn|Bhattacharya|Bollen|Daalder|2012|pp=47-52}}
* demand-supply balance need to be maintained, including the sufficient [[spinning reserve]]s for [[Contingency (electrical grid)|contingency]]. The balance need to reflect the transmission constraints;
* thermal units might have limits on minimum uptime (once switched on, cannot be turned off quickly) and downtime (once stopped, cannot be quickly restarted again);
* "must-run" units have to run due to technical constraints (for example, [[combined heat and power]] plants must run if their heat is needed);
Line 19:
== Hours-ahead operation ==
{{main|Merit order}}
In the hours prior to the delivery, a system operator might need to deploy additional [[supplemental reserve]]s 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
=== Dispatch curve ===
{{Box|{{#chart:DispatchCurve.chart}}|align=right|width=50%}}
| hAnnotationsValues={"text": "System lambda", "y": 60} -->▼
▲| vAnnotationsValues={"text": "Expected demand", "x": 150}
▲| hAnnotationsValues={"text": "System lambda", "y": 60}
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):<ref name=psu/>
* 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 plant]]s there are multiple cost curves depending on the mode of operation, so the power-cost relationship is not necessarily [[Monotonic function|monotonic]]).<ref name="BayónGarcía NietoGrau2013">{{cite journal | last1 = Bayón | first1 = L. | last2 = García Nieto | first2 = P. J. | last3 = Grau | first3 = J. M. | last4 = Ruiz | first4 = M. M. | last5 = Suárez | first5 = P. M. | title = An economic dispatch algorithm of combined cycle units | journal = International Journal of Computer Mathematics | date = 19 March 2013 | volume = 91 | issue = 2 | pages = 269–277 | issn = 0020-7160 | eissn = 1029-0265 | doi = 10.1080/00207160.2013.770482 | pmid = | s2cid = 5930756 | url = https://www.unioviedo.es/bayon/osh/41.pdf}}</ref>
[[File:Hypothetical dispatch curve, USA, Summer 2011.png|thumb|500px|Hypothetical dispatch curve (USA, summer 2011)<ref>{{cite web |title=Electric generator dispatch depends on system demand and the relative cost of operation |url=https://www.eia.gov/todayinenergy/detail.php?id=7590# |website=eia.gov |access-date=30 May 2022 |date=17 August 2012}}</ref>]]
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
=== 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.<ref name="SongWang2003">{{cite book | editor1 = Yong-Hua Song | editor2 = Xi-Fan Wang | author = Yong-Hua Song | date = 31 July 2003 | title = Operation of Market-oriented Power Systems | publisher = Springer Science & Business Media | page = 150 | isbn = 978-1-85233-670-7 | oclc = 1112226019 | chapter = System Redispatch | chapter-url = https://books.google.com/books?id=sS33yLR0U7EC&pg=PA150}}</ref>
== 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
== Control after disturbance ==
{{main|Frequency control|Voltage control and reactive power management}}
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 generator]]s): 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,{{sfn|NERC|2021|p=1}} 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").{{sfn|NERC|2021|p=6}}
=== Seconds-after control ===
The {{vanchor|Primary control|text=''primary control''}} is engaged automatically
* induction motors self-adjust (lower frequency reduces the energy use);
* under-frequency relays disconnect [[interruptible load]]s;
* [[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.{{sfn|NERC|2021|p=12}} This is the parameter that is approximated by the [[Frequency bias (electrical grid)|frequency bias]] coefficient of the [[area control error]] (ACE) calculation used for [[automatic generation control]].{{sfn|NERC|2021|p=14}}
=== Minutes-after control ===
The {{vanchor|Secondary control|text=''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]])
=== Tertiary control ===
The ''tertiary control'' involves reserve deployment and restoration to handle the current and future contingencies.{{sfn|NERC|2011|p=13}}
=== 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.{{sfn|Bevrani|Watanabe|Mitani|2014|p=158}} Another emergecy control action is [[islanding]].{{sfn|Bevrani|Watanabe|Mitani|2014|p=178}}
== Time control ==
{{main|Time error correction (TEC)}}
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
== References ==
{{
== Sources ==
* {{cite book | first1 = Antonio J. |last1 = Conejo | first2 = Luis | last2 = Baringo | date = 5 December 2017 | title = Power System Operations | publisher = Springer | pages = | isbn = 978-3-319-69407-8 | oclc = 1015677828 |
* {{cite book | first1 = Kankar | last1 = Bhattacharya | first2 = Math H.J. | last2 = Bollen | first3 = Jaap E. | last3 = Daalder | date = 6 December 2012 | title = Operation of Restructured Power Systems | publisher = Springer Science & Business Media | pages = | isbn = 978-1-4615-1465-7 | oclc = 852788650 | url = https://books.google.com/books?id=PtLgBwAAQBAJ}}
* {{cite web |last1=McCalley |first1=James D. |title=Introduction to System Operation, Optimization, and Control |url=https://home.engineering.iastate.edu/~jdm/ee553/Intro.pdf |website=iastate.edu |publisher=[[Iowa State University]] |access-date=30 May 2022}}
Line 75 ⟶ 78:
* {{cite web |last1=WECC |title=Balancing Authority and Regulation Overview |url=https://www.wecc.org/Administrative/06-Balancing%20Authority%20Overview.pdf |website=wecc.org |publisher=[[Western Electricity Coordinating Council]]}}
* {{cite book |last1=NERC |title=Reliability Functional Model Technical Document Version 5.1 |date=July 2018 |publisher=[[North American Electric Reliability Corporation]] |url=https://www.nerc.com/pa/Stand/Functional%20Model%20Advisory%20Group%20DL/FM_Technical_Document_V5-1_clean_10082019.pdf}}
* {{cite book |last1=NERC |title=Balancing and Frequency Control |date=January 26, 2011 |publisher=[[North American Electric Reliability Corporation]] |url=https://www.nerc.com/comm/OC/BAL0031_Supporting_Documents_2017_DL/NERC%20Balancing%20and%20Frequency%20Control%20040520111.pdf}}
* {{cite book |last1=NERC |title=Balancing and Frequency Control |date=May 11, 2021 |publisher=[[North American Electric Reliability Corporation]] |url=https://www.nerc.com/comm/OC/ReferenceDocumentsDL/Reference_Document_NERC_Balancing_and_Frequency_Control.pdf}}
* {{cite book | last=Kundur | first=P. | last2=Balu | first2=N.J. | last3=Lauby | first3=M.G. | title=Power System Stability and Control | publisher=McGraw-Hill Education | series=EPRI power system engineering series | year=1994 | isbn=978-0-07-035958-1 | url=https://books.google.com/books?id=wOlSAAAAMAAJ | access-date=2023-06-12}}
[[Category:Electric power generation]]
[[Category:Power engineering]]
| |||