1 List of Figures
2. A high-level overview of power system concepts, phenomena and processes, services & markets relevant within operational timeframes (bounded by the red dashed box). All non-faded text in the bottom section indicates a process, service and/or market related to active power balancing. All bold red text in the bottom section indicates a process, service and/or market related to active power balancing that is discussed in detail in this thesis. Timeframes, phenomena and stability categories were adapted from Machowski et al. (2020) and Hatziargyriou et al. (2021). The figure concept and layout was inspired by a similar figure presented in Wilson (2020).
-3. Mechanical power applied to the prime mover results in a mechanical torque T_m on the rotor of a synchronous generator. This is opposed by an electromagnetic torque T_e that is produced from the interaction of the rotor and stator magnetic fields. Source: (Rebours2009?).
+3. Mechanical power applied to the prime mover results in a mechanical torque T_m on the rotor of a synchronous generator. This is opposed by an electromagnetic torque T_e that is produced from the interaction of the rotor and stator magnetic fields. Source: Rebours (2009)
4. (a) A trace of power system frequency with corresponding frequency control services following a loss-of-generation contingency event. (b) The timeframes over which the various frequency control services are provided. Source: (AustralianEnergyMarketOperator2020l?).
@@ -316,7 +291,7 @@
4.3.1 Synchronous and control areas
A network area that is operated at a (constant) nominal AC frequency is known as a synchronous area. During stable operation, AC frequency should be close to the system’s nominal value and more-or-less uniform across the synchronous area. A control area, on the other hand, is a network area in which a system operator (SO) is responsible for maintaining a balance between supply and demand for electrical power. Whether the term “power system” refers to a synchronous area or a control area is often dependent on context — in particular, the relationship between the two in the jurisdiction in question. In eastern and southern Australia, the National Electricity Market’s (NEM) single control area consists of two synchronous areas (see Section 4.6 for further detail). In contrast, other jurisdictions have a single synchronous area composed of several electrically-connected control areas demarcated by political rather than physical boundaries. For example, continental Europe is a single synchronous area consisting of many national or trans-national control areas, and the continental United States has three synchronous areas (two of which extend into Canada) with over 60 control areas (North American Electric Reliability Corporation, 2023; Schittekatte and Pototschnig, 2022)
4.4 Power system operations
-
In broad terms, operating a power system involves the direction or control of power system resources — generators, loads, network elements and energy storage resources (which can act as both a generator and a load). In practice, however, power system operation is inseparable from the economic objective imposed upon SOs: minimise system costs (or under some market paradigms described in Section 2.5, maximise the value of trade) whilst 1) continuously maintaining a balance between active power supply & demand and 2) ensuring that system resources & the system itself are operated within their respective technical envelopes (Wood et al., 2014). The latter constraint implies stable & secure operation and is a prerequisite for the former constraint, which more-or-less corresponds to reliable operation1.
+
In broad terms, operating a power system involves the direction or control of power system resources — generators, loads, network elements and energy storage resources (which can act as both a generator and a load). In practice, however, power system operation is inseparable from the economic objective imposed upon SOs: minimise system costs (or under some market paradigms described in Section 2.4.2, maximise the value of trade) whilst 1) continuously maintaining a balance between active power supply & demand and 2) ensuring that system resources & the system itself are operated within their respective technical envelopes (Wood et al., 2014). The latter constraint implies stable & secure operation and is a prerequisite for the former constraint, which more-or-less corresponds to reliable operation1.
Noting that planning & investment have a large bearing on the manner in which a power system is operated (and vice versa), Figure 2 presents a high-level overview of power system phenomena and processes, services & markets that are most pertinent to active power balancing in operational timeframes, with those discussed in detail within this thesis highlighted in bold red text.
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4.4.2 The need for system balance
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4.4.2.1 Synchronism
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Following synchronisation, generators (e.g. turbines) and loads (e.g. motors) that rotate at a speed proportional to the power system frequency are known as synchronous machines. As shown in [eq:synch_speed], the synchronous speed is dependent on the number of poles of the machine and the power system frequency (Grainger1994?).
-
N_s = \frac{120f}{P}
- \label{eq:synch_speed}
-
where N_s is the synchronous speed in revolutions per minute, P is the number of magnetic poles and f is the electrical frequency in Hz.
-
Power system frequency control is required for the stable operation of a synchronous area. Should synchronous machines be exposed to high RoCoFs and sufficiently serious frequency deviations, they may experience equipment-damaging vibrations (Ulbig2014?) or suffer from pole slipping due to a loss of synchronism (DGAConsulting2016?). As such, if frequency control services are insufficient in their response, under-frequency load shedding (UFLS) relays or over-frequency generation shedding (OFGS) relays, and frequency-sensitive equipment protection relays are used as emergency frequency control schemes and equipment protection measures, respectively (Eto2018?; AustralianEnergyMarketCommission2019?).
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The activation of these schemes is undesirable, particularly as UFLS is reflected in power system reliability metrics. Moreover, the presence and configuration of these schemes in the power system means that if frequency deviations are sufficiently large, a cascading series of trips and faults may aggravate the active power imbalance and lead to power system black-out and collapse (Ulbig2014?; Hartmann2019?).
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4.4.3 Threats to system balance
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As highlighted in [eq:swing_area], the AC frequency of a power system can deviate from its nominal value when there is an imbalance between power supply and demand in the synchronous area. Active power imbalances are the result of power system variability and uncertainty.
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4.4.3.1 Variability
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Variability refers to expected or forecast fluctuations in the balance of active power supply and demand (Ela2011?). Sources of variability include fluctuations in load, oscillatory active power output from synchronous generators and changing weather conditions (e.g. cloud cover, wind speed) that may affect the active power output of VRE (Ela2011?; Bloom2017?; Riesz2015a?).
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4.4.3.2 Uncertainty
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Uncertainty refers to unexpected fluctuations in the balance of active power supply and demand (Ela2011?). Power system uncertainty encompasses the unanticipated behaviour of generators, loads and network elements. This includes unexpected outages (known as contingency events) and weather forecast errors that lead to VRE generation forecast error (Ela2011?; Riesz2015a?)
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4.5 Operational paradigms
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4.4.2 Operational paradigms
Synchronous areas can be subdivided into control areas, which are typically demarcated by the network boundaries of separate electric utilities or electricity markets (Grainger1994?; Elgerd1971?). Within a control area, the control of AC frequency is the responsibility of a system operator.
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4.5.1 Vertically-integrated
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4.4.2.1 Vertically-integrated
Historically, this configuration enabled economies of scale in both asset investment and operation to be achieved by electric utilities, particularly regulated monopolies that owned and operated most, if not all, of the generation, transmission and distribution infrastructure within a power system and were responsible for the retail of electricity to the end-user (these regulated monopolies are known as vertically-integrated utilities) (Masters2004?).
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4.5.2 Restructuring and the emergence of wholesale electricity markets
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4.4.2.2 Restructuring and the emergence of wholesale electricity markets
In mandatory pool markets, the system operator commits and dispatches individual generators (and, in some cases, loads) in the day-ahead and real-time markets, respectively, based on economic optimisation processes that incorporate transmission constraints and stability and reliability requirements. These processes are security-constrained unit commitment (SCUC), which is executed in the day-ahead market, and security-constrained economic dispatch (SCED), which is executed just prior to the relevant real-time market interval. In many mandatory pool markets, SCED and SCUC co-optimise the provision of energy and frequency control services
It should be noted that these processes are not exclusive to mandatory pool markets and could be used by vertically-integrated utilities to efficiently schedule resources in the power system (Grainger1994?).
-
4.5.2.1 Electricity industry restructuring
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4.4.2.2.1 Electricity industry restructuring
Beginning in the early 1990s, perceived inefficiencies and overspend by monopoly electric utilities, advancements in small low-upfront cost gas turbine technologies and the successful liberalisation of other industries such as airlines and telecommunications prompted many countries to restructure their electricity industries (Weigt2009?; Miller2017?). A common feature of this process across power systems was the implementation of a wholesale market for electricity, where generators compete for the opportunity to supply electricity and earn revenue through an auction-based mechanism (Milligan2017?).
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4.5.2.2 Electricity market structures and features
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4.5.2.2.1 System operator
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4.4.2.2.2 Electricity market structures and features
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4.4.2.2.2.1 System operator
In restructured electricity industries, the implementation of wholesale markets was accompanied by the creation of an independent power system operator to operate the transmission network, manage and administer the electricity market, maintain short-term power system reliability (the ability to meet demand with supply) and security (the ability to operate the power system within a defined operating envelope), and carry out longer term planning functions (Sioshansi2006?; Hogan2008?). These entities may own transmission infrastructure as a regulated monopoly, as is the case with the various Transmission System Operators (TSOs) in Europe, or be independent of any infrastructure ownership, such as the Independent System Operators (ISOs) and Regional Transmission Operators (RTOs) in North America and the Australian Energy Market Operator (AEMO).
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4.5.2.2.2 Market models
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4.4.2.2.2.2 Market models
The restructuring process proceeded differently across jurisdictions, resulting in the implementation of different wholesale market mechanisms. However, at a higher level, electricity markets worldwide have generally converged towards two main market models which are distinguished by the degree of centralisation of market operations and the role of the system operator (2):
Decentralised bilateral markets, in which suppliers enter into contracts with buyers either directly or through intermediaries (Barroso2005?). Whilst scheduling and dispatch is managed by market participants, intended energy schedules (i.e. net contract positions) are submitted by market participants ahead of time to the system operator, who is responsible for determining the requirement for and procuring frequency control services (known as balancing services in bilateral markets) (Hirth2015?). This model is the dominant market model in Europe.
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4.5.2.2.3 Market platforms
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4.4.2.2.2.3 Market platforms
Whilst other commodity markets are settled continuously or sequentially, reliability and security considerations and concerns have led to electricity markets being divided into discrete platforms(Isemonger2006?). Platforms are formal sub-markets for energy that are settled at different times. A platform implemented by all electricity markets is a real-time, or spot, market. Where implemented, additional platforms involve trade for one or more real-time market intervals but are each settled at different times ahead of the spot market. These additional platforms can reduce uncertainty for the system operator and provide market participants with a formal market mechanism for managing risk (Isemonger2006?; EnergySecurityBoard2020c?).
The number and type of platforms a particular market implements is often related to its market model. European bilateral markets often have a real-time market, a day-ahead market and intra-day markets, where day-ahead commitments may be traded continuously between market participants (Ahlqvist2018Central-Markets?). In contrast, however, it is practical to limit the number of platforms in a mandatory pool market due to the inflexibility of commitment ‘contracts’ determined by computationally complex optimisation processes (Isemonger2006?; Ahlqvist2018Central-Markets?). North American ISO/RTO markets have two platforms - a financially binding day-ahead market and a physically and financially binding real-time spot market (Cramton2017?). The Australian NEM is rather unique amongst mandatory pool markets as it only has a single platform - the real-time spot market. This arrangement means that while dispatch is centralised, participants manage the commitment of their generation portfolio with the assistance of pre-dispatch forecasts provided by AEMO (Riesz2016a?).
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4.6 Balancing processes and mechanisms
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4.6.1 Inherent inertial response
-
Synchronous machines convert electrical energy to mechanical energy, or vice versa, through the interacting magnetic fields of the rotor and the stator (Chapman2011ElectricFundamentals?). In a synchronous generator, this interaction produces an electromagnetic torque (T_e) on the rotor that opposes the mechanical torque (T_m) supplied by a prime mover (4). From [eq:swing], which is known as the swing equation, we can see that if a generator is at synchronous speed (i.e. steady state) and there is a transient increase in the electrical load of the power system (equivalent to an increase in P_e), the rotor of a synchronous generator will begin to decelerate as its stored kinetic energy is converted to electrical energy (Grainger1994?; Elgerd1971?). When this electromechanical response is observed across synchronous machines, the decrease in rotor speed will result in a decrease in the synchronous area’s AC frequency as per [eq:synch_speed]. The inverse is true for a decrease in electrical load - the synchronous area’s AC frequency will increase. These inherent responses describe a synchronous machine’s inertial response. J\omega_{sm}\frac{d\omega_{sm}}{dt} = P_m - P_e
- \label{eq:swing}
-
where \omega_{sm} is the rotor shaft velocity, J is moment of inertia of the rotor, P_m is mechanical power due to T_m and P_e is electrical power due to T_e.
+
4.5 Active power balancing
+
In theory, active power balancing is simply a consequence of the law of conservation of energy: the energy supplied through primary energy conversion or by energy storage into a network node is equal to the sum of the energy dissipated, stored and consumed at the same network node at each and every moment. In practice, however, it involves the moment-to-moment control of generation and loads to balance active power supply and demand across the power system. Moment-to-moment control is required because it is still uneconomical in many jurisdictions to store electricity at scale (i.e. in the same order of magnitude as generation and demand) despite grid-scale storage cost reductions (International Energy Agency, 2022), and though electricity can be transported close to the speed of light across the network, balancing required coordination across the power system because of transmission losses and network constraints imposed by line thermal limits, stability requirements & Kirchoff’s circuit laws (Hirth et al., 2016; Kirschen and Strbac, 2004).
+
4.5.1 Why is it required?
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Unlike the transportation networks of many other commodities, an imbalance between active power supply & demand can lead to deviations in technical parameters — voltage and frequency — that not only have the potential to damage equipment connected to the power system, but also to trigger a system collapse (Borenstein et al., 2023). As such, maintaining active power balance is essential to proper resource and system functioning.
+
4.5.1.1 The relationship between active power balance & AC frequency
+
Because synchronous machines are present in most power systems, system active power balance is closely tied to the system’s AC frequency. During steady state operation, synchronous machines rotate at a synchronous speed (N_s) that is proportional to the nominal system frequency (f) (Equation ¿eq:synch_speed?) (Chapman, 2011):
+
N_s = \frac{120f}{P} \label{eq:synch_speed}
+
where N_s is the synchronous speed in revolutions per minute, P is the number of (rotor) magnetic poles and f is the electrical frequency in hertz.
+
The link between active power imbalance and synchronous speed/system frequency can be elucidated by examining synchronous machine dynamics. In a synchronous generator (coal-fired, gas-fired and hydro generators), the interaction between the interacting magnetic fields of the rotor and stator produces an electromagnetic torque (T_e) on the rotor that opposes the mechanical torque (T_m) supplied by a prime mover (e.g. steam turbine) (Figure 3). Equation ¿eq:swing?, which is an energy balance variation of what is known as the swing equation, shows that if there is a transient increase in the electrical load of the power system (equivalent to an increase in P_e and thus T_e), the rotor of a synchronous generator will begin to decelerate as its stored kinetic energy is converted to electrical energy (Elgerd, 1971; Grainger, 1994).
where \omega_{sm} is the synchronous machine rotor shaft velocity, J is moment of inertia of the rotor, P_m is mechanical power, T_m is mechanical torque, P_e is electrical power and T_e is electromagnetic torque.
-
-Figure 3: Mechanical power applied to the prime mover results in a mechanical torque T_m on the rotor of a synchronous generator. This is opposed by an electromagnetic torque T_e that is produced from the interaction of the rotor and stator magnetic fields. Source: (Rebours2009?).
+
+Figure 3: Mechanical power applied to the prime mover results in a mechanical torque T_m on the rotor of a synchronous generator. This is opposed by an electromagnetic torque T_e that is produced from the interaction of the rotor and stator magnetic fields. Source: Rebours (2009)
-
4.6.1.1 Active power imbalance and RoCoF
-
We arrive at the relationship between the active power imbalance (P_{gen}-P_{load}) in a power system and AC frequency in [eq:swing_area] by extending the dynamics of the swing equation from a single synchronous generator to all synchronous generators in the synchronous area (Tamrakar2017?). [eq:swing_area] demonstrates that the rate of change of frequency (RoCoF) is proportional to the active power imbalance and inversely proportional to the system’s inertia constant, H. [eq:swing_area] is primarily concerned with synchronous generators, not loads, as the rotors of the former store more kinetic energy due to a larger physical mass and higher rotational speeds (Ulbig2014?; Denholm2020?). \frac{2H}{f}\frac{df}{dt} = \frac{P_{gen}-P_{load}}{S_{g, total}}
- \label{eq:swing_area} where H is the inertia constant of the synchronous area (H=\sum_{g} H_g, where H_g = \frac{J_g \omega^2}{2S_g}), f is the AC frequency, \frac{df}{dt} is the rate of change of frequency or RoCoF, S_{g,total} is the total apparent power of synchronous generators, and P_{gen} and P_{load} are the system’s total power supply and total power demand (including losses), respectively.
-
4.6.2 Load damping response
-
Another inherent electromechanical response is that of frequency-dependent loads, which include machinery driven by induction motors (AustralianEnergyMarketOperator2019l?). The power consumption of frequency-dependent loads decreases with lower frequencies and increases with higher frequencies. This is known as load damping, as the response reduces the imbalance in active power supply and demand and hence dampens the change in AC frequency as described in [eq:swing_area](Denholm2020?). However, load damping is diminishing in power systems around the world as a growing share of load is coupled to the power system through power electronic controllers, which enable loads to operate independently of the power system frequency (Undrill2018?).
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4.7 The role of frequency control services
+
The relationship between the active power imbalance in a power system (P_{gen}-P_{load}) and AC frequency is obtained by extending the dynamics of the swing equation from a single synchronous generator to all synchronous generators in a synchronous area (Equation ¿eq:swing_area?). Equation ¿eq:swing_area? shows that the rate of change of frequency (RoCoF) is proportional to the active power imbalance and inversely proportional to the system’s inertia constant, H. This form of the swing equation only models the inertial response of synchronous generators, and not the load damping response offered by (frequency-dependent) induction motor loads. Generation inertial response typically plays a large role in electromechanical system dynamics as the high speed and mass of generator rotors mean that they store significant quantities of kinetic energy (Denholm et al., 2020; Ulbig et al., 2014).
where H is the inertia constant of the synchronous area (H=\sum_{g} H_g, where H_g = \frac{J_g(2\pi f)^2}{2S_g}), f is the AC frequency, \frac{df}{dt} is the rate of change of frequency or RoCoF, S_{g,total} is the total apparent power of synchronous generators, and P_{gen} and P_{load} are the system’s total power supply and total power demand (including losses), respectively.
+
Equation ¿eq:swing_area? also shows that a power system’s AC frequency is an indicator of active power balance (Baggini, 2008). Insufficient generation will lead to a decrease in system frequency (i.e. negative RoCoF) and oversupply will lead to an increase in system frequency (i.e. positive RoCoF).
+
4.5.1.2 The consequences of frequency deviations
+
Serious power system frequency deviations away from the nominal value can have harmful effects. Synchronous machines may experience equipment-damaging vibrations (Ulbig et al., 2014), and both synchronous machines and transformers can overheat and fail if they operate outside their rated voltage-frequency limits (Kirby et al., 2002). Synchronous machines are also vulnerable to damage from high RoCoFs due to pole slipping (DGA Consulting, 2016). For these reasons, frequency-sensitive relays are often used to protect power system resources from frequency excursions.
+
However, these same protection measures can also trigger the complete collapse of the power system. Should the disconnection of a resource following a relay trip exacerbate an existing active power imbalance, the system frequency may deviate further and result in further disconnections. Situations such as these are known as cascading failures and can lead to a total system collapse (a blackout). Blackouts can have devastating social & economic consequences and require long & complex system restoration procedures before the power system can be returned to normal operation (Kirschen and Strbac, 2004). As such, SOs often employ emergency frequency control schemes that trip loads in the event of under-frequency (under-frequency load shedding or UFLS) or generation in the event of over-frequency (over-frequency generation shedding or OFGS) as a last line of defence against frequency-driven system collapse (Australian Energy Market Operator, 2021a; Hartmann et al., 2019).
+
4.5.2 Threats to system balance
+
As highlighted in [eq:swing_area], the AC frequency of a power system can deviate from its nominal value when there is an imbalance between power supply and demand in the synchronous area. Active power imbalances are the result of power system variability and uncertainty.
+
4.5.2.1 Variability
+
Variability refers to expected or forecast fluctuations in the balance of active power supply and demand (Ela2011?). Sources of variability include fluctuations in load, oscillatory active power output from synchronous generators and changing weather conditions (e.g. cloud cover, wind speed) that may affect the active power output of VRE (Ela2011?; Bloom2017?; Riesz2015a?).
+
4.5.2.2 Uncertainty
+
Uncertainty refers to unexpected fluctuations in the balance of active power supply and demand (Ela2011?). Power system uncertainty encompasses the unanticipated behaviour of generators, loads and network elements. This includes unexpected outages (known as contingency events) and weather forecast errors that lead to VRE generation forecast error (Ela2011?; Riesz2015a?)
+
4.6 Balancing processes and mechanisms
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Power system frequency control is required for the stable operation of a synchronous area. lianEnergyMarketCommission2019]. Trigger of emergency control schemes is undesirable as it affects reliability utcomes
+
4.6.1 The role of frequency control services
As discussed in 2.4, SCED is executed by vertically-integrated utilities and in mandatory pool electricity markets to ensure that active power supply and demand is efficiently balanced subject to network constraints and system security and reliability requirements. Between, and potentially across consecutive SCED processes (dispatch intervals) and unit commitment schedules, frequency control services are used by the system operator to manage both small and large instantaneous active power imbalances that may arise due to variability and uncertainty.
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4.8 Conventional frequency control scheme and services
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4.6.2 Conventional frequency control scheme and services
Power system operators typically employ a hierarchical and sequential control scheme to contain AC frequency within as narrow a band as possible, particularly during contingency events (Undrill2018?; Ela2011?). This control scheme involves the use of generation or load units with reserve capacity that provide frequency control services (Ela2011?). For these units to mitigate power system frequency deviations, they must have reserve capacity in the form of headroom (the ability to increase active power output) to respond to an under-frequency event, footroom (the ability to decrease active power output) to respond to an over-frequency event, or both (Eto2010a?). Under-frequency events are generally of greater concern to the system operator (e.g. loss of large generator). The various frequency control services differ based on their purpose, activation method, response time and control method (5). In the following subsections, we outline frequency control services that are common in many power systems.
Figure 4: (a) A trace of power system frequency with corresponding frequency control services following a loss-of-generation contingency event. (b) The timeframes over which the various frequency control services are provided. Source: (AustralianEnergyMarketOperator2020l?).
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4.8.1 Inertial response
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4.6.2.1 Inertial response
As discussed in 3.3.1, synchronous machines have an inherent inertial response to AC frequency deviations that must be considered in the frequency control strategy of a power system. For a a given active power imbalance, the inertia constant of the synchronous area, H, determines the magnitude of the initial RoCoF following a contingency event (see [eq:swing_area]) and the speed at which the power system can be returned to the nominal frequency (Ulbig2014?; Hartmann2019?).
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4.8.2 Primary frequency control
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4.6.2.2 Primary frequency control
The aim of primary frequency control (PFC) is to arrest the frequency deviation through the autonomous response of generators and frequency-responsive demand-response to locally-measured frequency deviations that exceed a certain control dead-band (Ela2012b?; Wang2003?; AustralianEnergyMarketOperator2019e?). For generators, this is achieved through droop control, in which a deviation from synchronous speed corresponds to a change in the active power output of a generator according to its droop characteristic (6, from A to B along L_0) (Eto2018?; Ela2012b?). Droop control is implemented through the turbine governors of synchronous generators or the inverter control system for IBR (Undrill2018?). Provided there is a sufficient amount of PFC reserve to arrest the system frequency, the speed of PFC determines the frequency zenith or frequency nadir, which are the maximum or minimum system frequency, respectively, following an active power imbalance event (Eto2010a?). PFC can be activated in response to small (tight dead-band) or contingency (wide dead-band) imbalance events and should ideally be sustained until secondary frequency control can take over (Eto2018?).
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4.8.3 Secondary frequency control
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4.6.2.3 Secondary frequency control
Secondary frequency control (SFC) replaces PFC and can consist of either or both of a synchronous area secondary control system known as an Automatic Generation Control (AGC) or unit-level load controllers (the latter is illustrated in 6) (Undrill2018?; Eto2018?; Undrill2019?). The most common strategy is for a synchronous area AGC to implement proportional-integral control on the Area Control Error (ACE) with a tie-line bias (Machowski2020?; Ela2011?). To minimise ACE and return the power system to its nominal frequency, the AGC sends signals to SFC units every 4 to 10 seconds to adjust their active power output in response to a frequency deviation (Eto2018?). When used to respond to smaller imbalance events, SFC is typically known as regulation(Ela2011?; Hewicker2020?).
Figure 5: Behaviour of a synchronous generator with a turbine governor providing PFC and responding to SFC. L_0 is the initial droop characteristic. The generator is initially operating at point A with an active power output of P_{M0}. System frequency (and hence the synchronous sped of the turbine) decreases from \omega_0 to \omega_1 and the turbine governor responds by moving the turbine along the droop characteristic to point B, thus increasing its active power output to P_{M1}. Following this, SFC changes the reference speed setpoint of the governor, moving the droop characteristic to L_1 and returning the system to frequency \omega_0. Source: (Wang2003?).
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4.8.4 Tertiary frequency control
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4.6.2.4 Tertiary frequency control
Tertiary frequency control (TFC) is intended to replace PFC and SFC. TFC is typically used as a margin of safety in systems where relatively infrequent unit commitment or rescheduling processes may be required to correct an active power imbalance (Hewicker2020?). Some systems, such as the NEM, do not procure TFR and instead rely solely upon a SCED that is frequently executed (Billimoria2020?).
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4.8.5 Dispatch and unit commitment
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4.8.5.1 Security-constrained economic dispatch
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4.6.2.5 Dispatch and unit commitment
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4.6.2.6 Security-constrained economic dispatch
SCED aims to determine the minimum cost operating configuration for committed generation such that a short-term forecast or actual demand can be met subject to subject to network constraints and stability and reliability requirements (Grainger1994?; Wood2014?). As generators typically submit offers for generation (and in some cases, frequency control) as piecewise linear cost functions, the SCED problem is less computationally complex than SCUC and can be solved using linear programming techniques (Wood2014?). For a given real-time market interval, SCED produces a set of physically and financially binding dispatch instructions, which include generation setpoints and enablement for frequency control services, and locational marginal prices for energy and frequency control services (Cramton2017?). In multi-platform markets such as the ISO/RTO markets, SCED is considered a sub-problem of unit commitment and is run for every real-time market interval ( 5-15 minutes) (Wood2014?; InternationalRenewableEnergyAgency2019?). In single-platform markets, such as the NEM, market participants manage their own unit commitment and SCED is the only market process that produces a binding schedule (AustralianEnergyRegulator2016?).
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4.8.5.2 Security-constrained unit commitment
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4.6.2.7 Security-constrained unit commitment
The aim of SCUC is to determine the minimum cost subset of generation that should be committed (i.e. synchronised and ready to deliver power to the power system) to meet a demand forecast for a set of future market intervals subject to network constraints and stability and reliability requirements (Wood2014?). SCUC is a computationally complex non-linear problem in many electricity markets because it considers non-convexities such as start-up costs and minimum operating costs in addition to an offer for energy (Cramton2017?; Isemonger2009?). The outcomes of solving this problem are an ahead schedule, which is often only financially binding, and locational marginal prices for energy and frequency control services for a future set of market intervals, such as the next day when SCUC is executed in day-ahead markets. SCUC can be beneficial for market participants that wish to hedge their production or consumption (Isemonger2006?). Furthermore, it offers certainty around power system outcomes to the system operator, and around market outcomes to generators that have long lead times and significant costs associated with commitment (e.g. baseload coal power plant) or generators that primarily consider opportunity costs, rather than marginal costs, when determining whether it is profitable to provide energy (e.g. hydroelectric power plants, battery energy storage systems) (Wood2014?; Cadwalader1998ReliabilityPricing?).
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4.8.6 Longer-term scheduling
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4.9 Emerging challenges in power system operations
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4.9.1 Inverter-based resources and frequency control
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4.6.2.8 Longer-term scheduling
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4.6.3 Emerging challenges
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4.6.3.1 Inverter-based resources and frequency control
Inverter-based resources (IBR) include variable IBR (solar PV and Type III and Type IV wind turbines (Wu2018?)), BESS and high voltage direct current (HVDC) links that connect to a power system through power electronic devices. The impacts of variable IBR on frequency control are of particular interest to system operators and market designers as many power systems are currently experiencing high instantaneous penetrations of variable IBR (in excess of 50%) and because many more are expected to do so in the future (AustralianEnergyMarketOperator2019?; IRENA2020?).
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4.9.2 Challenges posed by inverter-based resources
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4.6.3.1.1 Challenges posed by inverter-based resources
High penetrations of IBR in power systems pose challenges to frequency control due to their characteristics, particularly in islanded power systems or weakly-interconnected control areas that cannot rely on a wider synchronous area for frequency control services (Hodge2020?). These include (Kroposki2019?):
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4.9.2.1 Interface to power system
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4.6.3.1.1.1 Interface to power system
As IBR interface to a synchronous area through inverters, they are not electromagnetically coupled to the power system and therefore do not exhibit the inherent inertial response of synchronous generators. This has two main implications. The first is that reduced inertial response may affect power system stability during transients (e.g. rotor angle stability) (Tielens2016?), and the second is that a lack of inertia in the power system can lead to higher RoCoF and therefore more severe frequency nadirs or zeniths and the tripping of emergency protection schemes that would otherwise not occur in high inertia systems (Machowski2020?; Ulbig2014?; Hartmann2019?; Dreidy2017?).
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4.9.2.2 Variability and uncertainty
+
4.6.3.1.1.2 Variability and uncertainty
The aggregate degree of power system variability and uncertainty is likely to increase with higher penetrations of variable IBR (Riesz2015a?; AustralianEnergyMarketOperator2020b?). Variability not only encompasses active power output variability during a dispatch interval, which depends on the primary energy source and plant location and configuration, but also includes large ramps due to the correlated active power output of variable IBR over longer timeframes (Keeratimahat2019a?; AustralianEnergyMarketOperator2020d?). Power system uncertainty will depend on the accuracy of weather and generation forecasting, generator reliability and may also be a function of the degree of visibility and control a system operator has over IBR, particularly distributed energy resources such as rooftop solar PV and electric vehicles (AustralianEnergyMarketOperator2020d?; Wurth2019?; AustralianEnergyMarketOperator2020m?).
-
4.9.3 Provision of frequency control services
+
4.6.3.1.2 Provision of frequency control services
The presence of synchronous machines and grid-following inverters makes inertial response and frequency control necessary for secure and stable operation of a power system. At high instantaneous penetrations, low short-run marginal cost IBR may displace synchronous generators that have traditionally provided inertial response and frequency control services, and the load damping response may be minimal (Riesz2015a?; Tielens2012?). In these cases, the instantaneous inertia constant of the system may be low and IBR may be needed to assist in frequency control (Hartmann2019?; Tielens2012?). Through their inverter control system, IBR are able exercise rapid and precise control of their active power, within the constraints of primary or stored energy, to provide what is known as fast frequency response (FFR) (Machowski2020?; Hodge2020?).
-
4.9.3.1 Fast frequency response
+
4.6.3.1.2.1 Fast frequency response
FFR can generally be provided within a matter of milliseconds to provide a sustained active power response similar to PFC or to mitigate high RoCoF events (AEMO2017a?; Miller2017?). In response to an under-frequency event, a sustained active power raise response, similar to PFC, can be achieved by implementing frequency droop control in the inverter of a BESS, or that of a variable IBR that has been deloaded to provide headroom. Wind turbines can be deloaded through pitch angle or over speed control, whereas solar PV is typically deloaded through over-voltage control (Dreidy2017?; Tielens2012?; Fernandez-Guillamon2019a?). A sustained lower response can be delivered by operating an inverter control system at an off-maximum power point to reduce the IBR’s active power output.
High RoCoF can be mitigated by FFR that is delivered through processes and controls that mimic the inertial response of a synchronous generator (Eriksson2018?). Inertia-based FFR (otherwise known as synthetic inertia in the literature) is provided by extracting the kinetic energy from a wind turbine rotor to rapidly inject active power (Miller2017?) into the power system. FFR from virtual inertia, on the other hand, is provided as the result of implementing the dynamic model of a synchronous machine to some degree within an inverter control system (Tamrakar2017?; Anderson-Cook2013?). As FFR requires some form of measurement and is not inherent, it cannot be considered to be a direct substitute for inertial response (Miller2017?; AEMO2017a?).
-
4.10 Procurement of frequency control services
+
4.6.4 Designing operational practices
+
4.6.4.1 Procurement of frequency control services
As highlighted by (Ela2012b?) and (Billimoria2020?), frequency control services are typically procured through a combination of market-based mechanisms, such as remunerative schemes or contract or spot markets, and regulatory mechanisms, such as connection requirements or system operator intervention.
-
4.10.1 Market-based mechanisms
-
4.10.1.1 Suitability of markets
+
4.6.4.1.1 Market-based mechanisms
+
4.6.4.1.1.1 Suitability of markets
Many restructured electricity industries have developed competitive ancillary services markets that enable frequency control services to be procured alongside primary markets for energy and/or capacity provision. Competitive markets are a suitable mechanism for procuring frequency control services as AC frequency is a global parameter and, as such, frequency control services can be provided by any capable resource within a synchronous area (Billimoria2020?; Hirst1998?). This supports greater participation and competition in frequency control markets. Furthermore, frequency control services and energy are essentially the same commodity (active power) but differentiated by their delivery methods, with the former providing reserve capacity that responds in the event of a frequency deviation and the latter providing sustained delivery of active power during a market interval. Given that these products are related, there are benefits related to reducing overall system costs, incentivising frequency control provision and improving trade outcomes for market participants by co-optimising markets for energy and frequency control services (Ela2016?).
-
4.10.1.2 Opportunity costs and co-optimisation
+
4.6.4.1.1.2 Opportunity costs and co-optimisation
To provide raise frequency control services, generation must allocate reserve capacity, which may be at the expense of profitable energy provision (Raineri2006?). As such, participation in ancillary services markets often entails an opportunity cost to market participants. While frequency control services markets are often co-optimised with energy markets to ensure that power system energy supply and security requirements are met at the lowest cost to the system, participant opportunity costs can be accounted for in two ways in mandatory pool electricity markets:
In partially co-optimised frequency control services markets, perceived opportunity costs are incorporated into bids by market participant. The procurement of frequency control services and energy is co-optimised by the system operator in SCUC and/or SCED, thereby minimising overall costs to the system (Isemonger2009?).
In fully co-optimised frequency control services markets, market participants submit bids for energy and frequency control services provision. The system operator then determines a price for frequency control services that is the sum of the bid offer and the opportunity cost of that resource foregoing provision of energy or other services. The system operator can then co-optimise all bids and costs in SCUC and/or SCED so as to simultaneously maximise profit for market participants whilst minimising overall costs to the system (Ela2012a?; IntelligentEnergySystems2010a?).
-
4.10.1.3 Potential benefits of market-based mechanisms
+
4.6.4.1.1.3 Potential benefits of market-based mechanisms
Compensation for frequency control services addresses the externality of providing ancillary services, particularly if the compensation is aligned with a market participant’s opportunity costs (Rebours2007b?). Furthermore, if compensation is delivered through market-based mechanisms and if these mechanisms are designed well, frequency control services can be procured at least cost to the system from resources that are best placed to provide them within an operational timeframe (productive efficiency) and spur efficient investment in frequency control capabilities by market participants into the future (dynamic efficiency) (Thorncraft2007?; Riesz2015b?; Biggar2014TheMarkets?; AustralianEnergyMarketCommission2020a?).
-
4.10.1.4 Challenges in frequency control services markets
+
4.6.4.1.2 Challenges in frequency control services markets
Frequency control services markets face both existing and emerging challenges to achieving productive and dynamically efficient outcomes. The main challenges being faced in these markets are outlined below:
-
4.10.1.4.1 Product design and fungibility.
+
4.6.4.1.2.1 Product design and fungibility.
Products in existing frequency control services markets generally reflect the capabilities and requirements of conventional frequency control provided by synchronous generators (EU-SysFlex2019?). As frequency control abilities and needs have changed over time, various jurisdictions have considered or created additional frequency control services. These include ramping products, which have been implemented in some ISO/RTO markets in response to increasing variability and uncertainty (Ela2019?; Ela2017?), FFR products to mitigate RoCoF (Ela2019?; Fernandez-Munoz2020?) and TFC or operating reserves where operating reserve margins are a concern to the system operator (EnergySecurityBoard2020?).
Furthermore, there are trade-offs associated with the separation and fungibility of both existing and new frequency control products. Market-based mechanisms will work best when a particular frequency control product is a fungible and well defined, or “discrete”, commodity supplied by various providers (Gimon2020?). With a sufficiently large market, prices should reflect the costs incurred by various providers to provide such a service (Ela2012b?). This, however, ignores the wide “spectrum” of technical capabilities of power system resources with respect to frequency control.
Understanding the trade-offs in creating fungible new products is important to frequency control service market design. For example, while a new product may value and incentivise the provision of a particular frequency response (Ela2012b?), a market may not deliver a net benefit if there is limited competition or the costs and complexity of administering a market are significant (Rebours2007b?; Ela2019?).
-
4.10.1.4.2 Price formation.
+
4.6.4.1.2.2 Price formation.
Price formation is an unresolved issue within frequency control services market design. Ideally, the price of provision should be explicit, transparent and recognise the true value of the service alongside any opportunity-costs incurred by the supplying participant. There are three main issues that hamper efficient price formation and hence productive and dynamically efficient market outcomes:
Frequency control products are arbitrarily defined by a system operator and often procured in a single-sided market due to the public good nature of frequency control (Billimoria2020?; Pollitt2019a?). As such, the true value of these services to power system users is not recognised (Rebours2007b?).
Furthermore, in co-optimised markets, there is a tension between the relatively low opportunity costs of existing synchronous generation providing frequency control services and the strong price signals needed to incentivise new capabilities, particularly from high capital, low operating cost inverter-based resources (Ela2019?).
Some products, such as inertia, may be ‘lumpy’ in their provision and inseparable from other system security products (Billimoria2020?; EnergySecurityBoard2020?).
-
4.10.1.4.3 Cost allocation.
+
4.6.4.1.2.3 Cost allocation.
In many mandatory pool markets, the cost of frequency control services procured by the system operator is allocated to loads, even though the deviation of generation may cause the need for procurement in the first place (Milligan2011a?). Australia’s NEM has a ‘Causer Pays’ cost allocation framework in place for frequency control services procured for contingency response and regulation, though the mechanism for the latter suffers from a lack of transparency, complexity and fundamental design flaws (Riesz2015b?; AustralianEnergyMarketCommission2020?; AustralianEnergyRegulator2020?). Cost allocation could provide disincentives for undesirable behaviour, such as deviation from SCED dispatch instruction, and create counter-parties for hedging frequency control services price risk and therefore assist in price formation (Thorncraft2007?). As the power system continues to transition, it may be possible to allocated costs based on a ‘User Pays’ framework, whereby power system resources that impose frequency zenith, nadir or RoCoF limits pay for frequency control services (AustralianEnergyMarketCommission2020a?).
-
4.10.1.4.4 IBR participation.
+
4.6.4.1.2.4 IBR participation.
IBR cannot or do not participate in many frequency control services markets. Historically, literature has focused on the impact of variable IBR on frequency control-related integration costs and how these costs can be minimised (Ela2011?; Riesz2015b?). However, for reasons discussed in 5 and as demonstrated by variable IBR frequency control trials (AEMO2018d?; Loutan2017?) and the provision of frequency control services by BESS (AustralianEnergyMarketOperator2018i?), there is both a growing need for and benefit to IBR providing frequency control services. In markets such as Australia’s NEM, many IBR can participate in frequency control services markets but choose not to as their business models rely on revenue from energy provision and the opportunity-cost of participation is too high (AEMO2018d?). An active area of interest is designing frequency control services markets and the revenue earned within them to incentivise IBR participation and investment in frequency control capabilities, particularly as system security requirements change over time and as high instantaneous IBR penetrations are often associated with low energy prices (Ela2019?; EnergySecurityBoard2020?).
-
4.10.2 Regulatory mechanisms
+
4.6.4.1.3 Regulatory mechanisms
Regulatory mechanisms, such as equipment technical standards, grid codes and system operator intervention, were used by monopoly electric utilities and system operators to procure sufficient frequency control response prior to implementation of frequency control services markets. Even now, regulatory mechanisms are used in conjunction with market-based mechanisms to procure frequency control services. In fact, the processes of designing and regulating market rules are in and of themselves regulatory mechanisms (Sioshansi2006?).
-
4.10.2.1 Potential benefits of regulatory mechanisms
+
4.6.4.1.3.1 Potential benefits of regulatory mechanisms
Regulatory mechanisms are ideal for mandating basic frequency control capabilities as a condition for access or where markets may be difficult to design or suffer from major flaws such as a concentration of market power, oversupply of a product or the issues discussed in 6.1.4(Ela2012b?).
-
4.10.2.2 Shortfalls of regulatory mechanisms
+
4.6.4.1.3.2 Shortfalls of regulatory mechanisms
It may be difficult for regulatory mechanisms to ensure that sufficient frequency control services can be procured in power systems and electricity markets that are rapidly facing more power electronic-based control systems, lower levels of operational inertial response and higher variability and uncertainty of different scales and nature. Prescriptive regulatory mechanisms, such as grid codes, are often only updated after a number of years to reduce the compliance burden placed on connecting generators and loads. As such, they are slow to respond to changing frequency control capabilities and requirements. This delay can make new standards and requirements reactive rather than proactive. For example, AEMO can only review generator technical performance standards every 5 years (AustralianEnergyMarketCommission2018?), a timeframe in which the solar PV capacity installed in the NEM has more than tripled (2014-2019) (AustralianPVInstitute?).
-
4.10.2.3 Regulatory requirements as a solution to market failures
+
4.6.4.1.3.3 Regulatory requirements as a solution to market failures
Regulatory mechanisms are being increasingly used in power system jurisdictions where frequency control services markets have failed to incentivise or procure or appropriate capabilities and services, or where there is significant uncertainty around frequency response from generation. For example, several power systems, including the Australian NEM, have mandated some degree of PFC provision from connected generators in their grid codes or market rules (AustralianEnergyMarketCommission2020?; Roberts2018?). Similarly, frequency response has also been specified as a requirement for new generation (primarily IBR) to access and connect to the NEM and ISO/RTO markets in the U.S. (AustralianEnergyMarketCommission2018?; FederalEnergyRegulatoryCommissionFERC2018?).
-
4.10.2.4 Role of regulatory mechanisms
+
4.6.4.2 Role of regulatory mechanisms
Though processes across several jurisdictions are underway to address frequency control services market deficiencies (e.g. the Australian NEM’s post-2025 market design project (EnergySecurityBoard2020?), the Electric Reliability Council of Texas’ (ERCOT) Nodal Protocol Revision Request (Ela2019?) and the EU-SysFlex project (EU-SysFlex2019?)), there has been relatively little work around what role regulatory mechanisms may play, how they interact with market-based mechanisms and the relative benefits and costs of further frequency control services marketisation, both now and into the future.
-
4.11 Designing frequency control arrangements
+
4.6.5 Designing frequency control arrangements
Designing frequency control arrangements is a control, regulatory and market design problem which has become more complex in recent years due to electricity industry restructuring and growing penetrations of IBR (VanderVeen2016?).
-
4.11.1 Outcomes of good design
+
4.6.5.1 Outcomes of good design
It is important to define desired outcomes of the design process. Below, we present three outcomes that have previously been proposed for designing ancillary/system services arrangements (including frequency control arrangements) by (Rebours2007b?) and the (AustralianEnergyMarketCommission2020a?).
Effectiveness. This entails both sufficient quantity and performance of procured frequency control services to ensure that power system security requirements are met.
Efficiency. Efficient frequency control arrangements will procure services at the lowest cost to the system, both now (productive efficiency) and into the future (dynamic efficiency). Furthermore, efficient arrangements should also procure the right mix of services according to user and/or system needs (allocative efficiency).
Minimising procurement costs and complexity. Procurement and verification of delivery of frequency control services may involve significant costs associated with facilitation and monitoring. This could include metering equipment, IT systems and additional staffing costs. Complex procurement arrangements may also have unintended and unforeseen consequences on processes and markets that interface with these arrangements, such as the energy market and other ancillary services markets.
-
4.11.2 Complexity of the design process
+
4.6.5.2 Complexity of the design process
Designing frequency control arrangements is a complex exercise in managing interrelated and interacting capabilities, mechanisms and objectives (7). The frequency control capability of a power system is distinct from its performance, with a control strategy defining how the former translates to the latter. The frequency control capability of a power system is determined by the physical characteristics and configuration of generators, loads and network elements within a synchronous area.
Figure 6: A diagrammatic depiction of the complexity involved in designing power system frequency control arrangements.
Frequency control services from capable resources are often mandated through connection requirements or power system operator intervention (see 6.2), incentivised through remunerative schemes, or procured through a contract or spot market (see 6.1) (Billimoria2020?). Together with the control specification of frequency control products, these mechanisms define a power system control strategy that dictates how capable system resources respond to deviations, and therefore determine the frequency control performance of a power system. The outcomes that define frequency control performance can be divided into physical performance criteria, which describe the effectiveness of frequency control services provided, and economic objectives, which relate to the productive, dynamic and price and cost-allocation efficiency of the arrangements.
-
4.11.2.1 Interactions between capability, strategy and performance
+
4.6.5.2.1 Interactions between capability, strategy and performance
These three design layers often interact. Technical capabilities may guide the design of the control strategy, and therefore the mechanisms that define frequency control performance. An example of such a process is the PJM Interconnection (an RTO) implementing a high frequency AGC signal designed for BESS providing fast regulation frequency control services (Benner2015?; Brooks2019?). Similarly, deficiencies in performance can be addressed through modifying the control strategy to procure additional or more suitable frequency control capability. The California and Midcontinent ISOs have introduced ramping products to address increasing variability and uncertainty in their power systems (Ela2016?; Ela2017?).
-
4.11.3 Diversity of design outcomes
+
4.6.5.3 Diversity of design outcomes
The design process has and will most likely continue to proceed differently across jurisdictions due to the diversity of both the technical capabilities of resources within power systems (see 4 and 5) and the different structures and features of various electricity markets (see 2) (Rebours2007b?). Existing frequency control arrangements across the world have been reviewed and compared extensively in the literature (Rebours2009?; Ela2011?; DGAConsulting2016?; Hewicker2020?; Rebours2007a?; Rebours2007?; Zhou2016?; ReishusConsultingLLC2017?; Banshwar2018?).
-
4.11.4 Design principles and considerations
+
4.6.5.4 Design principles and considerations
Previous literature has explored the key design considerations for frequency control arrangements. (Rebours2007b?) outline design principles for power pool markets related to the frequency control services procurement, price formation, cost-allocation and market structure, which includes how frequency control services are offered, remunerated and cleared in markets, in addition to market operation and regulation. (VanderVeen2016?) build upon the work of (Rebours2007b?) to provides a more comprehensive treatment of frequency control arrangement design variables and performance criteria. The key contribution of (VanderVeen2016?) is that they explore some of the trade-offs between performance criteria when designing frequency control services markets. However, as they focus on the design challenge in European bilateral markets, some of these trade-offs are not relevant to or present in mandatory pool markets.
Both (Rebours2007b?) and (VanderVeen2016?) emphasise that good design will lead to efficient and effective frequency control arrangements. However, (VanderVeen2016?) focuses solely on market design whilst (Rebours2007b?) assesses various competitive procurement options but only briefly discusses the relative merits of compulsory provision of frequency control services through regulatory mechanisms. The work from these authors concentrates on achieving economic efficiency but pays relatively little attention to the technical capabilities of power system resources and the design of and interactions between frequency control products.
-
4.11.4.1 Holistic design
+
4.6.5.4.1 Holistic design
(Ela2012b?), (Billimoria2020?) and (MacGill2020a?) recognise that power system frequency control arrangements are typically composed of a mixture of market-based mechanisms and regulatory mechanisms that are compatible with the physics and control needs of the power system. The challenge here is determining the appropriate combination of these options for procurement, and the most suitable control mechanisms that account for both frequency control capabilities and the physical performance required by a power system. This can only be achieved by considering the interactions, or interfaces, between mechanisms within a power system’s frequency control strategy.
-
4.11.4.2 Interfaces
+
4.6.5.4.2 Interfaces
The concept of interfaces in electricity industry decision-making is distinct but coupled to the frequency control arrangement design layers discussed above. Interfaces were first formalised by (Thorncraft2007?), specifically with relation to the security decision-making interface between commercial decision-making processes (i.e. processes within market-based mechanisms) and the technical and physical processes and the requirements of the power system (i.e. frequency control capability and physical performance) (Thorncraft2009?).
-
4.11.4.2.1 Security decision-making interface.
+
4.6.5.4.2.1 Security decision-making interface.
The security decision-making interface includes system operator processes in integrated markets (e.g. SCUC and SCED) which co-optimise the provision of energy and frequency control services (Chow2005?). Literature has explored enhancing unit commitment and economic dispatch processes for frequency control through frequency response constraints (Ela2014?; Doherty2005?; Teng2015?; Mancarella2017a?) and, more recently, inertia constraints (Gu2020?; Johnson2020?). However, these studies implicitly assume that existing security decision-making processes and frequency control products are adequate and efficient, and will therefore perform well.
-
4.11.4.3 Interfaces between mechanisms in the frequency control strategy
+
4.6.5.4.2.2 Interfaces between mechanisms in the frequency control strategy
Interfaces change over time and with technological innovation (Thorncraft2009?). The arrival of highly-controllable loads and IBR in the power system warrants the consideration of a control system process that is separate from physical characteristics and processes (8).
Figure 7: Interfaces between the frequency control capability and the mechanisms within the frequency control strategy of a power system.
-
4.11.4.3.1 Interface between control and procurement mechanisms.
+
4.6.5.4.2.3 Interface between control and procurement mechanisms.
Some literature has begun to explore the interface between control mechanisms and market-based mechanisms. (Garcia2019a?) explore the impact of interchangeability between FFR and PFC on total system frequency control services costs. (Badesa2020?) outlined an optimisation framework that enables inertia, a reduction in contingency size and multi-speed PFC to be procured based on RoCoF and frequency nadir constraints and, more significantly, priced with a view of incentivising faster PFC and synthetic/virtual inertia provision from IBR. However, these studies do not consider how control mechanisms might interface with other regulatory mechanisms, such as equipment performance standards.
-
4.11.4.3.2 Interface between procurement mechanisms.
+
4.6.5.4.2.4 Interface between procurement mechanisms.
In framing the design challenge for power system security services in the NEM, (MacGill2020?), (Billimoria2020?) and (Skinner2020?) acknowledge that there is a choice between, or potential combination of regulatory mechanisms and market-based mechanisms for procurement, with the latter two exploring the various advantages and disadvantages of each option. In particular, (Billimoria2020?) explores various procurement models and how regulatory and market-based mechanisms may interact within them. However, these procurement models are highly generic and further work is required to determine how existing and emerging control mechanisms might be structured in each of the models. Furthermore, there is a need to understand how these procurement models might interface with and integrate into existing and emerging market processes if an optimum for the entire system is to be achieved (MacGill2020?).
-
4.12 Conclusion
+
4.7 Emerging challenges in power system operations
+
4.8 Conclusion
Frequency control is vital to the secure operation of a power system. The inherent characteristics and control systems of IBR differ from those of synchronous machines and this poses both opportunities and challenges to frequency control arrangements in mandatory pool markets with growing instantaneous penetrations of IBR. The frequency control performance of a power system is highly influenced by the frequency control strategy, which consists of the control mechanisms, electricity market design and the regulatory mechanisms that are in place, and the frequency control capability of its resources. Determining the appropriate combination of these mechanisms will require examining the interfaces between market-based, regulatory and control mechanisms and identifying the benefits, costs and trade-offs associated with particular design choices. This will enable electricity market designers to make an informed choice in implementing effective and efficient frequency control arrangements in low-carbon electricity markets.
5 Research framework
6 Frequency control arrangements: insights from the National Electricity Market
@@ -1478,6 +1457,9 @@
References
Australian PV Institute, n.d. Installed PV generation capacity by State/Territory [WWW Document]. URL https://pv-map.apvi.org.au (accessed 5.23.2022).
Banshwar, A., Sharma, N.K., Sood, Y.R., Shrivastava, R., 2018. An international experience of technical and economic aspects of ancillary services in deregulated power industry: Lessons for emerging BRIC electricity markets. Renewable and Sustainable Energy Reviews 90, 774–801. https://doi.org/10.1016/j.rser.2018.03.085
@@ -1487,9 +1469,15 @@
References
Billimoria, F., Mancarella, P., Poudineh, R., 2020. Market design for system security in low-carbon electricity grids: From the physics to the economics. Oxford Institute for Energy Studies. https://doi.org/10.26889/9781784671600
Brooks, A.E., Lesieutre, B.C., 2019. A review of frequency regulation markets in three U.S. ISO/RTOs. Electricity Journal 32, 106668. https://doi.org/10.1016/j.tej.2019.106668
+
+Chapman, S.J., 2011. Electric Machinery Fundamentals. McGraw-Hill Education.
+
Hewicker, C., Kumar, A., Arappil, M., 2020. Dimensioning of Control Reserves in Southern Region Grid States. Deutsche Gesellschaft für Internationale Zusammenarbeit GmbH.
Hirth, L., Ziegenhagen, I., 2015. Balancing power and variable renewables: Three links. Renewable and Sustainable Energy Reviews 50, 1035–1051. https://doi.org/10.1016/j.rser.2015.04.180
Kirby, B.J., Dyer, J., Martinez, C., Shoureshi, R.A., Guttromson, R., Dagle, J., 2002. Frequency Control Concerns In The North American Electric Power System. Oak Ridge National Laboratory.
+
+Kirschen, D., Strbac, G., 2004. Fundamentals of Power System Economics: Kirschen/Power System Economics. John Wiley & Sons, Ltd, Chichester, UK. https://doi.org/10.1002/0470020598
+
Kristov, L., De Martini, P., Taft, J.D., 2016. A Tale of Two Visions: Designing a Decentralized Transactive Electric System. IEEE Power and Energy Magazine 14, 63–69. https://doi.org/10.1109/MPE.2016.2524964
+Rebours, Y., 2009. A Comprehensive Assessment of Markets for Frequency and Voltage Control Ancillary Services. The University of Manchester.
+
Rebours, Y.G., Kirschen, D.S., Trotignon, M., Rossignol, S., 2007b. A Survey of Frequency and Voltage Control Ancillary Services - Part II: Economic Features. IEEE Transactions on Power Systems 22, 358–366. https://doi.org/10.1109/tpwrs.2006.888965
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@@ -318,7 +318,7 @@
\normalsize
UNSW Sydney, Australia\\
- October 27, 2023
+ October 31, 2023
% Except where otherwise noted, content in this thesis is licensed under a Creative Commons Attribution 4.0 License (http://creativecommons.org/licenses/by/4.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. Copyright 2015,Tom Pollard.
@@ -657,90 +657,8 @@ \subsection{Phenomena in operational
and solar photovoltaic (PV) generation.
\end{enumerate}
-\hypertarget{the-need-for-system-balance}{%
-\subsection{The need for system
-balance}\label{the-need-for-system-balance}}
-
-\hypertarget{synchronism}{%
-\subsubsection{Synchronism}\label{synchronism}}
-
-Following synchronisation, generators (e.g.~turbines) and loads (e.g.
-motors) that rotate at a speed proportional to the power system
-frequency are known as \emph{synchronous machines}. As shown in
-\protect\hyperlink{eq:synch_speed}{{[}eq:synch\_speed{]}}, the
-\emph{synchronous speed} is dependent on the number of poles of the
-machine and the power system frequency
-(\protect\hyperlink{ref-Grainger1994}{\textbf{Grainger1994?}}).
-
-\[N_s = \frac{120f}{P}
- \label{eq:synch_speed}\]
-
-where \(N_s\) is the synchronous speed in revolutions per minute, \(P\)
-is the number of magnetic poles and \(f\) is the electrical frequency in
-Hz.
-
-Power system frequency control is required for the stable operation of a
-synchronous area. Should synchronous machines be exposed to high RoCoFs
-and sufficiently serious frequency deviations, they may experience
-equipment-damaging vibrations
-(\protect\hyperlink{ref-Ulbig2014}{\textbf{Ulbig2014?}}) or suffer from
-pole slipping due to a loss of synchronism
-(\protect\hyperlink{ref-DGAConsulting2016}{\textbf{DGAConsulting2016?}}).
-As such, if frequency control services are insufficient in their
-response, \emph{under-frequency load shedding} (UFLS) relays or
-\emph{over-frequency generation shedding} (OFGS) relays, and
-frequency-sensitive equipment protection relays are used as emergency
-frequency control schemes and equipment protection measures,
-respectively (\protect\hyperlink{ref-Eto2018}{\textbf{Eto2018?}};
-\protect\hyperlink{ref-AustralianEnergyMarketCommission2019}{\textbf{AustralianEnergyMarketCommission2019?}}).
-
-The activation of these schemes is undesirable, particularly as UFLS is
-reflected in power system reliability metrics. Moreover, the presence
-and configuration of these schemes in the power system means that if
-frequency deviations are sufficiently large, a cascading series of trips
-and faults may aggravate the active power imbalance and lead to power
-system black-out and collapse
-(\protect\hyperlink{ref-Ulbig2014}{\textbf{Ulbig2014?}};
-\protect\hyperlink{ref-Hartmann2019}{\textbf{Hartmann2019?}}).
-
-\hypertarget{threats-to-system-balance}{%
-\subsection{Threats to system balance}\label{threats-to-system-balance}}
-
-As highlighted in
-\protect\hyperlink{eq:swing_area}{{[}eq:swing\_area{]}}, the AC
-frequency of a power system can deviate from its nominal value when
-there is an imbalance between power supply and demand in the synchronous
-area. Active power imbalances are the result of power system
-\emph{variability} and \emph{uncertainty}.
-
-\hypertarget{variability}{%
-\subsubsection{Variability}\label{variability}}
-
-Variability refers to expected or forecast fluctuations in the balance
-of active power supply and demand
-(\protect\hyperlink{ref-Ela2011}{\textbf{Ela2011?}}). Sources of
-variability include fluctuations in load, oscillatory active power
-output from synchronous generators and changing weather conditions
-(e.g.~cloud cover, wind speed) that may affect the active power output
-of VRE (\protect\hyperlink{ref-Ela2011}{\textbf{Ela2011?}};
-\protect\hyperlink{ref-Bloom2017}{\textbf{Bloom2017?}};
-\protect\hyperlink{ref-Riesz2015a}{\textbf{Riesz2015a?}}).
-
-\hypertarget{uncertainty}{%
-\subsubsection{Uncertainty}\label{uncertainty}}
-
-Uncertainty refers to unexpected fluctuations in the balance of active
-power supply and demand
-(\protect\hyperlink{ref-Ela2011}{\textbf{Ela2011?}}). Power system
-uncertainty encompasses the unanticipated behaviour of generators, loads
-and network elements. This includes unexpected outages (known as
-\emph{contingency events}) and weather forecast errors that lead to VRE
-generation forecast error
-(\protect\hyperlink{ref-Ela2011}{\textbf{Ela2011?}};
-\protect\hyperlink{ref-Riesz2015a}{\textbf{Riesz2015a?}})
-
\hypertarget{sec:lit_review-operational_paradigms}{%
-\section{Operational
+\subsection{Operational
paradigms}\label{sec:lit_review-operational_paradigms}}
Synchronous areas can be subdivided into \emph{control areas}, which are
@@ -752,7 +670,7 @@ \section{Operational
system operator.
\hypertarget{vertically-integrated}{%
-\subsection{Vertically-integrated}\label{vertically-integrated}}
+\subsubsection{Vertically-integrated}\label{vertically-integrated}}
Historically, this configuration enabled economies of scale in both
asset investment and operation to be achieved by electric utilities,
@@ -764,7 +682,7 @@ \subsection{Vertically-integrated}\label{vertically-integrated}}
(\protect\hyperlink{ref-Masters2004}{\textbf{Masters2004?}}).
\hypertarget{restructuring-and-the-emergence-of-wholesale-electricity-markets}{%
-\subsection{Restructuring and the emergence of wholesale electricity
+\subsubsection{Restructuring and the emergence of wholesale electricity
markets}\label{restructuring-and-the-emergence-of-wholesale-electricity-markets}}
In mandatory pool markets, the system operator commits and dispatches
@@ -784,7 +702,7 @@ \subsection{Restructuring and the emergence of wholesale electricity
(\protect\hyperlink{ref-Grainger1994}{\textbf{Grainger1994?}}).
\hypertarget{electricity-industry-restructuring}{%
-\subsubsection{Electricity industry
+\paragraph{Electricity industry
restructuring}\label{electricity-industry-restructuring}}
Beginning in the early 1990s, perceived inefficiencies and overspend by
@@ -801,11 +719,11 @@ \subsubsection{Electricity industry
(\protect\hyperlink{ref-Milligan2017}{\textbf{Milligan2017?}}).
\hypertarget{electricity-market-structures-and-features}{%
-\subsubsection{Electricity market structures and
+\paragraph{Electricity market structures and
features}\label{electricity-market-structures-and-features}}
\hypertarget{system-operator}{%
-\paragraph{System operator}\label{system-operator}}
+\subparagraph{System operator}\label{system-operator}}
In restructured electricity industries, the implementation of wholesale
markets was accompanied by the creation of an independent power system
@@ -823,7 +741,7 @@ \subsubsection{Electricity market structures and
North America and the Australian Energy Market Operator (AEMO).
\hypertarget{market-models}{%
-\paragraph{Market models}\label{market-models}}
+\subparagraph{Market models}\label{market-models}}
The restructuring process proceeded differently across jurisdictions,
resulting in the implementation of different wholesale market
@@ -880,7 +798,7 @@ \subsubsection{Electricity market structures and
from {}
\hypertarget{market-platforms}{%
-\paragraph{Market platforms}\label{market-platforms}}
+\subparagraph{Market platforms}\label{market-platforms}}
Whilst other commodity markets are settled continuously or sequentially,
reliability and security considerations and concerns have led to
@@ -918,105 +836,215 @@ \subsubsection{Electricity market structures and
pre-dispatch forecasts provided by AEMO
(\protect\hyperlink{ref-Riesz2016a}{\textbf{Riesz2016a?}}).
-\hypertarget{balancing-processes-and-mechanisms}{%
-\section{Balancing processes and
-mechanisms}\label{balancing-processes-and-mechanisms}}
+\hypertarget{active-power-balancing}{%
+\section{Active power balancing}\label{active-power-balancing}}
+
+In theory, \emph{active power balancing} is simply a consequence of the
+law of conservation of energy: the energy supplied through primary
+energy conversion or by energy storage into a network node is equal to
+the sum of the energy dissipated, stored and consumed at the same
+network node at each and every moment. In practice, however, it involves
+the \textbf{\emph{moment-to-moment control} of generation and loads to
+balance active power supply and demand \emph{across the power system}}.
+\emph{Moment-to-moment control} is required because it is still
+uneconomical in many jurisdictions to store electricity at scale
+(i.e.~in the same order of magnitude as generation and demand) despite
+grid-scale storage cost reductions
+(\protect\hyperlink{ref-internationalenergyagencyGridScaleStorage2022}{International
+Energy Agency, 2022}), and though electricity can be transported close
+to the speed of light across the network, balancing required
+coordination \emph{across the power system} because of transmission
+losses and network constraints imposed by line thermal limits, stability
+requirements \& Kirchoff's circuit laws
+(\protect\hyperlink{ref-hirthWhyWindNot2016a}{Hirth et al., 2016};
+\protect\hyperlink{ref-kirschenFundamentalsPowerSystem2004}{Kirschen and
+Strbac, 2004}).
+
+\hypertarget{why-is-it-required}{%
+\subsection{Why is it required?}\label{why-is-it-required}}
+
+Unlike the transportation networks of many other commodities, an
+imbalance between active power supply \& demand can lead to deviations
+in technical parameters --- voltage and frequency --- that not only have
+the potential to damage equipment connected to the power system, but
+also to trigger a system collapse
+(\protect\hyperlink{ref-borensteinEconomicsElectricityReliability2023}{Borenstein
+et al., 2023}). As such, maintaining active power balance is essential
+to proper resource and system functioning.
+
+\hypertarget{the-relationship-between-active-power-balance-ac-frequency}{%
+\subsubsection{The relationship between active power balance \& AC
+frequency}\label{the-relationship-between-active-power-balance-ac-frequency}}
+
+Because synchronous machines are present in most power systems, system
+active power balance is closely tied to the system's AC frequency.
+During steady state operation, synchronous machines rotate at a
+\emph{synchronous speed} (\(N_s\)) that is proportional to the nominal
+system frequency (\(f\)) (Equation~\ref{eq:synch_speed})
+(\protect\hyperlink{ref-chapmanElectricMachineryFundamentals2011}{Chapman,
+2011}):
-\hypertarget{sec:electromech}{%
-\subsection{Inherent inertial response}\label{sec:electromech}}
-
-Synchronous machines convert electrical energy to mechanical energy, or
-vice versa, through the interacting magnetic fields of the rotor and the
-stator
-(\protect\hyperlink{ref-Chapman2011ElectricFundamentals}{\textbf{Chapman2011ElectricFundamentals?}}).
-In a synchronous generator, this interaction produces an electromagnetic
-torque (\(T_e\)) on the rotor that opposes the mechanical torque
-(\(T_m\)) supplied by a prime mover
-(\protect\hyperlink{fig:synch_torques}{4}). From
-\protect\hyperlink{eq:swing}{{[}eq:swing{]}}, which is known as the
-\emph{swing equation}, we can see that if a generator is at synchronous
-speed (i.e.~steady state) and there is a transient increase in the
-electrical load of the power system (equivalent to an increase in
-\(P_e\)), the rotor of a synchronous generator will begin to decelerate
-as its stored kinetic energy is converted to electrical energy
-(\protect\hyperlink{ref-Grainger1994}{\textbf{Grainger1994?}};
-\protect\hyperlink{ref-Elgerd1971}{\textbf{Elgerd1971?}}). When this
-electromechanical response is observed across synchronous machines, the
-decrease in rotor speed will result in a decrease in the synchronous
-area's AC frequency as per
-\protect\hyperlink{eq:synch_speed}{{[}eq:synch\_speed{]}}. The inverse
-is true for a decrease in electrical load - the synchronous area's AC
-frequency will increase. These inherent responses describe a synchronous
-machine's \emph{inertial response}.
-\[J\omega_{sm}\frac{d\omega_{sm}}{dt} = P_m - P_e
- \label{eq:swing}\]
-
-where \(\omega_{sm}\) is the rotor shaft velocity, \(J\) is moment of
-inertia of the rotor, \(P_m\) is mechanical power due to \(T_m\) and
-\(P_e\) is electrical power due to \(T_e\).
+\[N_s = \frac{120f}{P} \label{eq:synch_speed}\]
+
+where \(N_s\) is the synchronous speed in revolutions per minute, \(P\)
+is the number of (rotor) magnetic poles and \(f\) is the electrical
+frequency in hertz.
+
+The link between active power imbalance and synchronous speed/system
+frequency can be elucidated by examining synchronous machine dynamics.
+In a synchronous generator (coal-fired, gas-fired and hydro generators),
+the interaction between the interacting magnetic fields of the rotor and
+stator produces an electromagnetic torque (\(T_e\)) on the rotor that
+opposes the mechanical torque (\(T_m\)) supplied by a prime mover
+(e.g.~steam turbine) (Figure~\ref{fig:synch_torques}).
+Equation~\ref{eq:swing}, which is an energy balance variation of what is
+known as the \emph{swing equation}, shows that if there is a transient
+increase in the electrical load of the power system (equivalent to an
+increase in \(P_e\) and thus \(T_e\)), the rotor of a synchronous
+generator will begin to decelerate as its stored kinetic energy is
+converted to electrical energy
+(\protect\hyperlink{ref-elgerdElectricEnergySystems1971}{Elgerd, 1971};
+\protect\hyperlink{ref-graingerPowerSystemAnalysis1994}{Grainger,
+1994}).
+
+\[J\omega_{sm}\frac{d\omega_{sm}}{dt} = P_m - P_e \label{eq:swing}\]
+
+where \(\omega_{sm}\) is the synchronous machine rotor shaft velocity,
+\(J\) is moment of inertia of the rotor, \(P_m\) is mechanical power,
+\(T_m\) is mechanical torque, \(P_e\) is electrical power and \(T_e\) is
+electromagnetic torque.
\begin{figure}
\hypertarget{fig:synch_torques}{%
\centering
-\includegraphics[width=0.6\textwidth,height=\textheight]{source/figures/swing.png}
+\includegraphics{source/figures/swing.png}
\caption{Mechanical power applied to the prime mover results in a
mechanical torque \(T_m\) on the rotor of a synchronous generator. This
is opposed by an electromagnetic torque \(T_e\) that is produced from
-the interaction of the rotor and stator magnetic fields. Source:
-(\protect\hyperlink{ref-Rebours2009}{\textbf{Rebours2009?}}).}\label{fig:synch_torques}
+the interaction of the rotor and stator magnetic fields. Source: Rebours
+(\protect\hyperlink{ref-reboursComprehensiveAssessmentMarkets2009}{2009})}\label{fig:synch_torques}
}
\end{figure}
-\hypertarget{active-power-imbalance-and-rocof}{%
-\subsubsection{Active power imbalance and
-RoCoF}\label{active-power-imbalance-and-rocof}}
-
-We arrive at the relationship between the active power imbalance
-(\(P_{gen}-P_{load}\)) in a power system and AC frequency in
-\protect\hyperlink{eq:swing_area}{{[}eq:swing\_area{]}} by extending the
+The relationship between the active power imbalance in a power system
+(\(P_{gen}-P_{load}\)) and AC frequency is obtained by extending the
dynamics of the swing equation from a single synchronous generator to
-all synchronous generators in the synchronous area
-(\protect\hyperlink{ref-Tamrakar2017}{\textbf{Tamrakar2017?}}).
-\protect\hyperlink{eq:swing_area}{{[}eq:swing\_area{]}} demonstrates
-that the rate of change of frequency (\emph{RoCoF}) is proportional to
-the active power imbalance and inversely proportional to the system's
-inertia constant, \(H\).
-\protect\hyperlink{eq:swing_area}{{[}eq:swing\_area{]}} is primarily
-concerned with synchronous generators, not loads, as the rotors of the
-former store more kinetic energy due to a larger physical mass and
-higher rotational speeds
-(\protect\hyperlink{ref-Ulbig2014}{\textbf{Ulbig2014?}};
-\protect\hyperlink{ref-Denholm2020}{\textbf{Denholm2020?}}).
-\[\frac{2H}{f}\frac{df}{dt} = \frac{P_{gen}-P_{load}}{S_{g, total}}
- \label{eq:swing_area}\] where \(H\) is the inertia constant of
-the synchronous area (\(H=\sum_{g} H_g\), where
-\(H_g = \frac{J_g \omega^2}{2S_g}\)), \(f\) is the AC frequency,
-\(\frac{df}{dt}\) is the rate of change of frequency or RoCoF,
-\(S_{g,total}\) is the total apparent power of synchronous generators,
-and \(P_{gen}\) and \(P_{load}\) are the system's total power supply and
-total power demand (including losses), respectively.
-
-\hypertarget{sec:load_damp}{%
-\subsection{Load damping response}\label{sec:load_damp}}
-
-Another inherent electromechanical response is that of
-frequency-dependent loads, which include machinery driven by induction
-motors
-(\protect\hyperlink{ref-AustralianEnergyMarketOperator2019l}{\textbf{AustralianEnergyMarketOperator2019l?}}).
-The power consumption of frequency-dependent loads decreases with lower
-frequencies and increases with higher frequencies. This is known as
-\emph{load damping}, as the response reduces the imbalance in active
-power supply and demand and hence dampens the change in AC frequency as
-described in \protect\hyperlink{eq:swing_area}{{[}eq:swing\_area{]}}
-(\protect\hyperlink{ref-Denholm2020}{\textbf{Denholm2020?}}). However,
-load damping is diminishing in power systems around the world as a
-growing share of load is coupled to the power system through power
-electronic controllers, which enable loads to operate independently of
-the power system frequency
-(\protect\hyperlink{ref-Undrill2018}{\textbf{Undrill2018?}}).
+all synchronous generators in a synchronous area
+(Equation~\ref{eq:swing_area}). Equation~\ref{eq:swing_area} shows that
+the rate of change of frequency (\emph{RoCoF}) is proportional to the
+active power imbalance and inversely proportional to the system's
+inertia constant, \(H\). This form of the swing equation only models the
+\emph{inertial response} of synchronous generators, and not the
+\emph{load damping} response offered by (frequency-dependent) induction
+motor loads. Generation inertial response typically plays a large role
+in electromechanical system dynamics as the high speed and mass of
+generator rotors mean that they store significant quantities of kinetic
+energy (\protect\hyperlink{ref-denholmInertiaPowerGrid2020}{Denholm et
+al., 2020}; \protect\hyperlink{ref-ulbigImpactLowRotational2014}{Ulbig
+et al., 2014}).
+
+\[\frac{2H}{f}\frac{df}{dt} = \frac{P_{gen}-P_{load}}{S_{g, total}} \label{eq:swing_area}\]
+
+where \(H\) is the inertia constant of the synchronous area
+(\(H=\sum_{g} H_g\), where \(H_g = \frac{J_g(2\pi f)^2}{2S_g}\)), \(f\)
+is the AC frequency, \(\frac{df}{dt}\) is the rate of change of
+frequency or RoCoF, \(S_{g,total}\) is the total apparent power of
+synchronous generators, and \(P_{gen}\) and \(P_{load}\) are the
+system's total power supply and total power demand (including losses),
+respectively.
+
+Equation~\ref{eq:swing_area} also shows that a power system's AC
+frequency is an indicator of active power balance
+(\protect\hyperlink{ref-bagginiHandbookPowerQuality2008}{Baggini,
+2008}). Insufficient generation will lead to a decrease in system
+frequency (i.e.~negative RoCoF) and oversupply will lead to an increase
+in system frequency (i.e.~positive RoCoF).
+
+\hypertarget{the-consequences-of-frequency-deviations}{%
+\subsubsection{The consequences of frequency
+deviations}\label{the-consequences-of-frequency-deviations}}
+
+Serious power system frequency deviations away from the nominal value
+can have harmful effects. Synchronous machines may experience
+equipment-damaging vibrations
+(\protect\hyperlink{ref-ulbigImpactLowRotational2014}{Ulbig et al.,
+2014}), and both synchronous machines and transformers can overheat and
+fail if they operate outside their rated voltage-frequency limits
+(\protect\hyperlink{ref-kirbyFrequencyControlConcerns2002}{Kirby et al.,
+2002}). Synchronous machines are also vulnerable to damage from high
+RoCoFs due to pole slipping
+(\protect\hyperlink{ref-dgaconsultingInternationalReviewFrequency2016}{DGA
+Consulting, 2016}). For these reasons, frequency-sensitive relays are
+often used to protect power system resources from frequency excursions.
+
+However, these same protection measures can also trigger the complete
+collapse of the power system. Should the disconnection of a resource
+following a relay trip exacerbate an existing active power imbalance,
+the system frequency may deviate further and result in further
+disconnections. Situations such as these are known as \emph{cascading
+failures} and can lead to a total system collapse (a \emph{blackout}).
+Blackouts can have devastating social \& economic consequences and
+require long \& complex system restoration procedures before the power
+system can be returned to normal operation
+(\protect\hyperlink{ref-kirschenFundamentalsPowerSystem2004}{Kirschen
+and Strbac, 2004}). As such, SOs often employ emergency frequency
+control schemes that trip loads in the event of under-frequency
+(\emph{under-frequency load shedding} or \emph{UFLS}) or generation in
+the event of over-frequency (\emph{over-frequency generation shedding}
+or \emph{OFGS}) as a last line of defence against frequency-driven
+system collapse
+(\protect\hyperlink{ref-australianenergymarketoperatorEnduringPrimaryFrequency2021}{Australian
+Energy Market Operator, 2021a};
+\protect\hyperlink{ref-hartmannEffectsDecreasingSynchronous2019}{Hartmann
+et al., 2019}).
+
+\hypertarget{threats-to-system-balance}{%
+\subsection{Threats to system balance}\label{threats-to-system-balance}}
+
+As highlighted in
+\protect\hyperlink{eq:swing_area}{{[}eq:swing\_area{]}}, the AC
+frequency of a power system can deviate from its nominal value when
+there is an imbalance between power supply and demand in the synchronous
+area. Active power imbalances are the result of power system
+\emph{variability} and \emph{uncertainty}.
+
+\hypertarget{variability}{%
+\subsubsection{Variability}\label{variability}}
+
+Variability refers to expected or forecast fluctuations in the balance
+of active power supply and demand
+(\protect\hyperlink{ref-Ela2011}{\textbf{Ela2011?}}). Sources of
+variability include fluctuations in load, oscillatory active power
+output from synchronous generators and changing weather conditions
+(e.g.~cloud cover, wind speed) that may affect the active power output
+of VRE (\protect\hyperlink{ref-Ela2011}{\textbf{Ela2011?}};
+\protect\hyperlink{ref-Bloom2017}{\textbf{Bloom2017?}};
+\protect\hyperlink{ref-Riesz2015a}{\textbf{Riesz2015a?}}).
+
+\hypertarget{uncertainty}{%
+\subsubsection{Uncertainty}\label{uncertainty}}
+
+Uncertainty refers to unexpected fluctuations in the balance of active
+power supply and demand
+(\protect\hyperlink{ref-Ela2011}{\textbf{Ela2011?}}). Power system
+uncertainty encompasses the unanticipated behaviour of generators, loads
+and network elements. This includes unexpected outages (known as
+\emph{contingency events}) and weather forecast errors that lead to VRE
+generation forecast error
+(\protect\hyperlink{ref-Ela2011}{\textbf{Ela2011?}};
+\protect\hyperlink{ref-Riesz2015a}{\textbf{Riesz2015a?}})
+
+\hypertarget{balancing-processes-and-mechanisms}{%
+\section{Balancing processes and
+mechanisms}\label{balancing-processes-and-mechanisms}}
+
+Power system frequency control is required for the stable operation of a
+synchronous area. lianEnergyMarketCommission2019{]}. Trigger of
+emergency control schemes is undesirable as it affects reliability
+utcomes
\hypertarget{the-role-of-frequency-control-services}{%
-\section{The role of frequency control
+\subsection{The role of frequency control
services}\label{the-role-of-frequency-control-services}}
As discussed in \protect\hyperlink{sec:scuc_sced}{2.4}, SCED is executed
@@ -1030,7 +1058,7 @@ \section{The role of frequency control
may arise due to variability and uncertainty.
\hypertarget{sec:conventional_freq_control}{%
-\section{Conventional frequency control scheme and
+\subsection{Conventional frequency control scheme and
services}\label{sec:conventional_freq_control}}
Power system operators typically employ a hierarchical and sequential
@@ -1067,7 +1095,7 @@ \section{Conventional frequency control scheme and
\end{figure}
\hypertarget{inertial-response}{%
-\subsection{Inertial response}\label{inertial-response}}
+\subsubsection{Inertial response}\label{inertial-response}}
As discussed in \protect\hyperlink{sec:electromech}{3.3.1}, synchronous
machines have an inherent inertial response to AC frequency deviations
@@ -1081,7 +1109,8 @@ \subsection{Inertial response}\label{inertial-response}}
\protect\hyperlink{ref-Hartmann2019}{\textbf{Hartmann2019?}}).
\hypertarget{primary-frequency-control}{%
-\subsection{Primary frequency control}\label{primary-frequency-control}}
+\subsubsection{Primary frequency
+control}\label{primary-frequency-control}}
The aim of primary frequency control (PFC) is to arrest the frequency
deviation through the autonomous response of generators and
@@ -1110,7 +1139,7 @@ \subsection{Primary frequency control}\label{primary-frequency-control}}
(\protect\hyperlink{ref-Eto2018}{\textbf{Eto2018?}}).
\hypertarget{secondary-frequency-control}{%
-\subsection{Secondary frequency
+\subsubsection{Secondary frequency
control}\label{secondary-frequency-control}}
Secondary frequency control (SFC) replaces PFC and can consist of either
@@ -1152,7 +1181,7 @@ \subsection{Secondary frequency
\end{figure}
\hypertarget{tertiary-frequency-control}{%
-\subsection{Tertiary frequency
+\subsubsection{Tertiary frequency
control}\label{tertiary-frequency-control}}
Tertiary frequency control (TFC) is intended to replace PFC and SFC. TFC
@@ -1165,7 +1194,7 @@ \subsection{Tertiary frequency
(\protect\hyperlink{ref-Billimoria2020}{\textbf{Billimoria2020?}}).
\hypertarget{dispatch-and-unit-commitment}{%
-\subsection{Dispatch and unit
+\subsubsection{Dispatch and unit
commitment}\label{dispatch-and-unit-commitment}}
\hypertarget{security-constrained-economic-dispatch}{%
@@ -1231,14 +1260,13 @@ \subsubsection{Security-constrained unit
\protect\hyperlink{ref-Cadwalader1998ReliabilityPricing}{\textbf{Cadwalader1998ReliabilityPricing?}}).
\hypertarget{longer-term-scheduling}{%
-\subsection{Longer-term scheduling}\label{longer-term-scheduling}}
+\subsubsection{Longer-term scheduling}\label{longer-term-scheduling}}
-\hypertarget{emerging-challenges-in-power-system-operations}{%
-\section{Emerging challenges in power system
-operations}\label{emerging-challenges-in-power-system-operations}}
+\hypertarget{emerging-challenges}{%
+\subsection{Emerging challenges}\label{emerging-challenges}}
\hypertarget{sec:ibr_freq}{%
-\subsection{Inverter-based resources and frequency
+\subsubsection{Inverter-based resources and frequency
control}\label{sec:ibr_freq}}
Inverter-based resources (IBR) include variable IBR (solar PV and Type
@@ -1254,7 +1282,7 @@ \subsection{Inverter-based resources and frequency
\protect\hyperlink{ref-IRENA2020}{\textbf{IRENA2020?}}).
\hypertarget{challenges-posed-by-inverter-based-resources}{%
-\subsection{Challenges posed by inverter-based
+\paragraph{Challenges posed by inverter-based
resources}\label{challenges-posed-by-inverter-based-resources}}
High penetrations of IBR in power systems pose challenges to frequency
@@ -1265,7 +1293,7 @@ \subsection{Challenges posed by inverter-based
(\protect\hyperlink{ref-Kroposki2019}{\textbf{Kroposki2019?}}):
\hypertarget{interface-to-power-system}{%
-\subsubsection{Interface to power
+\subparagraph{Interface to power
system}\label{interface-to-power-system}}
As IBR interface to a synchronous area through inverters, they are not
@@ -1284,7 +1312,7 @@ \subsubsection{Interface to power
\protect\hyperlink{ref-Dreidy2017}{\textbf{Dreidy2017?}}).
\hypertarget{variability-and-uncertainty}{%
-\subsubsection{Variability and
+\subparagraph{Variability and
uncertainty}\label{variability-and-uncertainty}}
The aggregate degree of power system variability and uncertainty is
@@ -1308,7 +1336,7 @@ \subsubsection{Variability and
\protect\hyperlink{ref-AustralianEnergyMarketOperator2020m}{\textbf{AustralianEnergyMarketOperator2020m?}}).
\hypertarget{provision-of-frequency-control-services}{%
-\subsection{Provision of frequency control
+\paragraph{Provision of frequency control
services}\label{provision-of-frequency-control-services}}
The presence of synchronous machines and grid-following inverters makes
@@ -1331,7 +1359,7 @@ \subsection{Provision of frequency control
\protect\hyperlink{ref-Hodge2020}{\textbf{Hodge2020?}}).
\hypertarget{fast-frequency-response}{%
-\subsubsection{Fast frequency response}\label{fast-frequency-response}}
+\subparagraph{Fast frequency response}\label{fast-frequency-response}}
FFR can generally be provided within a matter of milliseconds to provide
a sustained active power response similar to PFC or to mitigate high
@@ -1367,8 +1395,12 @@ \subsubsection{Fast frequency response}\label{fast-frequency-response}}
(\protect\hyperlink{ref-Miller2017}{\textbf{Miller2017?}};
\protect\hyperlink{ref-AEMO2017a}{\textbf{AEMO2017a?}}).
+\hypertarget{designing-operational-practices}{%
+\subsection{Designing operational
+practices}\label{designing-operational-practices}}
+
\hypertarget{sec:procurement}{%
-\section{Procurement of frequency control
+\subsubsection{Procurement of frequency control
services}\label{sec:procurement}}
As highlighted by (\protect\hyperlink{ref-Ela2012b}{\textbf{Ela2012b?}})
@@ -1379,10 +1411,10 @@ \section{Procurement of frequency control
or system operator intervention.
\hypertarget{sec:market_mech}{%
-\subsection{Market-based mechanisms}\label{sec:market_mech}}
+\paragraph{Market-based mechanisms}\label{sec:market_mech}}
\hypertarget{suitability-of-markets}{%
-\subsubsection{Suitability of markets}\label{suitability-of-markets}}
+\subparagraph{Suitability of markets}\label{suitability-of-markets}}
Many restructured electricity industries have developed competitive
\emph{ancillary services} markets that enable frequency control services
@@ -1406,7 +1438,7 @@ \subsubsection{Suitability of markets}\label{suitability-of-markets}}
(\protect\hyperlink{ref-Ela2016}{\textbf{Ela2016?}}).
\hypertarget{opportunity-costs-and-co-optimisation}{%
-\subsubsection{Opportunity costs and
+\subparagraph{Opportunity costs and
co-optimisation}\label{opportunity-costs-and-co-optimisation}}
To provide raise frequency control services, generation must allocate
@@ -1442,7 +1474,7 @@ \subsubsection{Opportunity costs and
\end{enumerate}
\hypertarget{potential-benefits-of-market-based-mechanisms}{%
-\subsubsection{Potential benefits of market-based
+\subparagraph{Potential benefits of market-based
mechanisms}\label{potential-benefits-of-market-based-mechanisms}}
Compensation for frequency control services addresses the externality of
@@ -1462,7 +1494,7 @@ \subsubsection{Potential benefits of market-based
\protect\hyperlink{ref-AustralianEnergyMarketCommission2020a}{\textbf{AustralianEnergyMarketCommission2020a?}}).
\hypertarget{sec:challgnes_fcas_markets}{%
-\subsubsection{Challenges in frequency control services
+\paragraph{Challenges in frequency control services
markets}\label{sec:challgnes_fcas_markets}}
Frequency control services markets face both existing and emerging
@@ -1470,7 +1502,7 @@ \subsubsection{Challenges in frequency control services
The main challenges being faced in these markets are outlined below:
\hypertarget{product-design-and-fungibility.}{%
-\paragraph{Product design and
+\subparagraph{Product design and
fungibility.}\label{product-design-and-fungibility.}}
Products in existing frequency control services markets generally
@@ -1512,7 +1544,7 @@ \subsubsection{Challenges in frequency control services
\protect\hyperlink{ref-Ela2019}{\textbf{Ela2019?}}).
\hypertarget{price-formation.}{%
-\paragraph{Price formation.}\label{price-formation.}}
+\subparagraph{Price formation.}\label{price-formation.}}
Price formation is an unresolved issue within frequency control services
market design. Ideally, the price of provision should be explicit,
@@ -1547,7 +1579,7 @@ \subsubsection{Challenges in frequency control services
\end{enumerate}
\hypertarget{cost-allocation.}{%
-\paragraph{Cost allocation.}\label{cost-allocation.}}
+\subparagraph{Cost allocation.}\label{cost-allocation.}}
In many mandatory pool markets, the cost of frequency control services
procured by the system operator is allocated to loads, even though the
@@ -1572,7 +1604,7 @@ \subsubsection{Challenges in frequency control services
(\protect\hyperlink{ref-AustralianEnergyMarketCommission2020a}{\textbf{AustralianEnergyMarketCommission2020a?}}).
\hypertarget{ibr-participation.}{%
-\paragraph{IBR participation.}\label{ibr-participation.}}
+\subparagraph{IBR participation.}\label{ibr-participation.}}
IBR cannot or do not participate in many frequency control services
markets. Historically, literature has focused on the impact of variable
@@ -1600,7 +1632,7 @@ \subsubsection{Challenges in frequency control services
\protect\hyperlink{ref-EnergySecurityBoard2020}{\textbf{EnergySecurityBoard2020?}}).
\hypertarget{sec:regulatory_mech}{%
-\subsection{Regulatory mechanisms}\label{sec:regulatory_mech}}
+\paragraph{Regulatory mechanisms}\label{sec:regulatory_mech}}
Regulatory mechanisms, such as equipment technical standards, grid codes
and system operator intervention, were used by monopoly electric
@@ -1613,7 +1645,7 @@ \subsection{Regulatory mechanisms}\label{sec:regulatory_mech}}
(\protect\hyperlink{ref-Sioshansi2006}{\textbf{Sioshansi2006?}}).
\hypertarget{potential-benefits-of-regulatory-mechanisms}{%
-\subsubsection{Potential benefits of regulatory
+\subparagraph{Potential benefits of regulatory
mechanisms}\label{potential-benefits-of-regulatory-mechanisms}}
Regulatory mechanisms are ideal for mandating basic frequency control
@@ -1624,7 +1656,7 @@ \subsubsection{Potential benefits of regulatory
(\protect\hyperlink{ref-Ela2012b}{\textbf{Ela2012b?}}).
\hypertarget{shortfalls-of-regulatory-mechanisms}{%
-\subsubsection{Shortfalls of regulatory
+\subparagraph{Shortfalls of regulatory
mechanisms}\label{shortfalls-of-regulatory-mechanisms}}
It may be difficult for regulatory mechanisms to ensure that sufficient
@@ -1645,7 +1677,7 @@ \subsubsection{Shortfalls of regulatory
(\protect\hyperlink{ref-AustralianPVInstitute}{\textbf{AustralianPVInstitute?}}).
\hypertarget{regulatory-requirements-as-a-solution-to-market-failures}{%
-\subsubsection{Regulatory requirements as a solution to market
+\subparagraph{Regulatory requirements as a solution to market
failures}\label{regulatory-requirements-as-a-solution-to-market-failures}}
Regulatory mechanisms are being increasingly used in power system
@@ -1681,7 +1713,7 @@ \subsubsection{Role of regulatory
marketisation, both now and into the future.
\hypertarget{sec:designing_arrangements}{%
-\section{Designing frequency control
+\subsection{Designing frequency control
arrangements}\label{sec:designing_arrangements}}
Designing frequency control arrangements is a control, regulatory and
@@ -1690,7 +1722,7 @@ \section{Designing frequency control
(\protect\hyperlink{ref-VanderVeen2016}{\textbf{VanderVeen2016?}}).
\hypertarget{outcomes-of-good-design}{%
-\subsection{Outcomes of good design}\label{outcomes-of-good-design}}
+\subsubsection{Outcomes of good design}\label{outcomes-of-good-design}}
It is important to define desired outcomes of the design process. Below,
we present three outcomes that have previously been proposed for
@@ -1724,7 +1756,7 @@ \subsection{Outcomes of good design}\label{outcomes-of-good-design}}
\end{enumerate}
\hypertarget{complexity-of-the-design-process}{%
-\subsection{Complexity of the design
+\subsubsection{Complexity of the design
process}\label{complexity-of-the-design-process}}
Designing frequency control arrangements is a complex exercise in
@@ -1764,7 +1796,7 @@ \subsection{Complexity of the design
cost-allocation efficiency of the arrangements.
\hypertarget{interactions-between-capability-strategy-and-performance}{%
-\subsubsection{Interactions between capability, strategy and
+\paragraph{Interactions between capability, strategy and
performance}\label{interactions-between-capability-strategy-and-performance}}
These three design layers often interact. Technical capabilities may
@@ -1782,7 +1814,7 @@ \subsubsection{Interactions between capability, strategy and
\protect\hyperlink{ref-Ela2017}{\textbf{Ela2017?}}).
\hypertarget{diversity-of-design-outcomes}{%
-\subsection{Diversity of design
+\subsubsection{Diversity of design
outcomes}\label{diversity-of-design-outcomes}}
The design process has and will most likely continue to proceed
@@ -1806,7 +1838,7 @@ \subsection{Diversity of design
\protect\hyperlink{ref-Banshwar2018}{\textbf{Banshwar2018?}}).
\hypertarget{design-principles-and-considerations}{%
-\subsection{Design principles and
+\subsubsection{Design principles and
considerations}\label{design-principles-and-considerations}}
Previous literature has explored the key design considerations for
@@ -1844,7 +1876,7 @@ \subsection{Design principles and
and interactions between frequency control products.
\hypertarget{holistic-design}{%
-\subsubsection{Holistic design}\label{holistic-design}}
+\paragraph{Holistic design}\label{holistic-design}}
(\protect\hyperlink{ref-Ela2012b}{\textbf{Ela2012b?}}),
(\protect\hyperlink{ref-Billimoria2020}{\textbf{Billimoria2020?}}) and
@@ -1860,7 +1892,7 @@ \subsubsection{Holistic design}\label{holistic-design}}
within a power system's frequency control strategy.
\hypertarget{interfaces}{%
-\subsubsection{Interfaces}\label{interfaces}}
+\paragraph{Interfaces}\label{interfaces}}
The concept of interfaces in electricity industry decision-making is
distinct but coupled to the frequency control arrangement design layers
@@ -1874,7 +1906,7 @@ \subsubsection{Interfaces}\label{interfaces}}
(\protect\hyperlink{ref-Thorncraft2009}{\textbf{Thorncraft2009?}}).
\hypertarget{security-decision-making-interface.}{%
-\paragraph{Security decision-making
+\subparagraph{Security decision-making
interface.}\label{security-decision-making-interface.}}
The security decision-making interface includes system operator
@@ -1895,7 +1927,7 @@ \subsubsection{Interfaces}\label{interfaces}}
will therefore perform well.
\hypertarget{interfaces-between-mechanisms-in-the-frequency-control-strategy}{%
-\subsubsection{Interfaces between mechanisms in the frequency control
+\subparagraph{Interfaces between mechanisms in the frequency control
strategy}\label{interfaces-between-mechanisms-in-the-frequency-control-strategy}}
Interfaces change over time and with technological innovation
@@ -1916,7 +1948,7 @@ \subsubsection{Interfaces between mechanisms in the frequency control
\end{figure}
\hypertarget{interface-between-control-and-procurement-mechanisms.}{%
-\paragraph{Interface between control and procurement
+\subparagraph{Interface between control and procurement
mechanisms.}\label{interface-between-control-and-procurement-mechanisms.}}
Some literature has begun to explore the interface between control
@@ -1934,7 +1966,7 @@ \subsubsection{Interfaces between mechanisms in the frequency control
performance standards.
\hypertarget{interface-between-procurement-mechanisms.}{%
-\paragraph{Interface between procurement
+\subparagraph{Interface between procurement
mechanisms.}\label{interface-between-procurement-mechanisms.}}
In framing the design challenge for power system security services in
@@ -1955,6 +1987,10 @@ \subsubsection{Interfaces between mechanisms in the frequency control
emerging market processes if an optimum for the entire system is to be
achieved (\protect\hyperlink{ref-MacGill2020}{\textbf{MacGill2020?}}).
+\hypertarget{emerging-challenges-in-power-system-operations}{%
+\section{Emerging challenges in power system
+operations}\label{emerging-challenges-in-power-system-operations}}
+
\hypertarget{conclusion}{%
\section{Conclusion}\label{conclusion}}
@@ -2151,8 +2187,8 @@ \section{Introduction}\label{sec:fcs-intro}}
VRE penetrations (just over 60\% in 2021) and is expected to experience
penetrations as high as 75-100\% by 2025
(\protect\hyperlink{ref-australianenergymarketoperatorNEMEngineeringFramework2021}{Australian
-Energy Market Operator, 2021a},
-\protect\hyperlink{ref-australianenergymarketoperatorQuarterlyEnergyDynamics2021}{2021b}).
+Energy Market Operator, 2021b},
+\protect\hyperlink{ref-australianenergymarketoperatorQuarterlyEnergyDynamics2021}{2021c}).
Though the NEM's frequency control arrangements were once arguably
world-leading
(\protect\hyperlink{ref-rieszFrequencyControlAncillary2015}{Riesz et
@@ -2788,7 +2824,7 @@ \subsection{Overview of the NEM}\label{overview-of-the-nem}}
security constraints. Much like ISO/RTO markets, energy and FCAS markets
are co-optimised with respect to technical feasibility and cost
(\protect\hyperlink{ref-australianenergymarketoperatorDispatchStandardOperating2019}{Australian
-Energy Market Operator, 2021c},
+Energy Market Operator, 2021d},
\protect\hyperlink{ref-australianenergymarketoperatorFCASModelNEMDE2017}{2017b}).
Real-time dispatch produces zonal marginal prices for energy and FCAS,
which form the basis for market settlement in each of the NEM's regions.
@@ -2858,7 +2894,7 @@ \subsection{FCAS markets}\label{fcas-markets}}
(\protect\hyperlink{ref-aureconLargeScaleBatteryStorage2019}{Aurecon,
2019};
\protect\hyperlink{ref-australianenergymarketoperatorAEMOVirtualPower2021}{Australian
-Energy Market Operator, 2021d};
+Energy Market Operator, 2021e};
\protect\hyperlink{ref-australianenergyregulatorStateEnergyMarket2021}{Australian
Energy Regulator, 2021}). However, these new entrants tend to offer
smaller volumes and there are still relatively few FCAS providers in the
@@ -2978,7 +3014,7 @@ \subsection{Challenges to frequency control posed by VRE and
deviations, some inverter models have been found to be non-compliant and
there is still a significant number of legacy systems in the NEM
(\protect\hyperlink{ref-australianenergymarketoperatorBehaviourDistributedResources2021}{Australian
-Energy Market Operator, 2021e};
+Energy Market Operator, 2021f};
\protect\hyperlink{ref-stringerConsumerLedTransitionAustralia2020}{Stringer
et al., 2020}).
@@ -3011,7 +3047,7 @@ \subsection{Challenges to frequency control posed by VRE and
distribution level given the significant installed capacities of rooftop
solar PV located within proximity of one another in suburban areas
(\protect\hyperlink{ref-australianenergymarketoperatorEnduringPrimaryFrequency2021}{Australian
-Energy Market Operator, 2021f}).
+Energy Market Operator, 2021a}).
\hypertarget{features-of-nem-frequency-control-arrangements}{%
\subsection{Features of NEM frequency control
@@ -3461,7 +3497,7 @@ \section{NEM assessment and outlook}\label{nem-assessment-and-outlook}}
frequency within the NOFB (see Figure~\ref{fig:mpfr_dist}) and reduced
excursions beyond the NOFB
(\protect\hyperlink{ref-australianenergymarketoperatorEnduringPrimaryFrequency2021}{Australian
-Energy Market Operator, 2021f}). As a result of this initial success and
+Energy Market Operator, 2021a}). As a result of this initial success and
further technical advice provided by AEMO, the AEMC has indicated that
it intends to retain mandatory PFR at a tight-deadband following the
``sunset'' of the initial rule
@@ -3478,7 +3514,7 @@ \section{NEM assessment and outlook}\label{nem-assessment-and-outlook}}
changes were made in late September 2020 and many generators moved to
final settings in late October 2020. Source: Australian Energy Market
Operator
-(\protect\hyperlink{ref-australianenergymarketoperatorEnduringPrimaryFrequency2021}{2021f}).}\label{fig:mpfr_dist}
+(\protect\hyperlink{ref-australianenergymarketoperatorEnduringPrimaryFrequency2021}{2021a}).}\label{fig:mpfr_dist}
}
\end{figure}
@@ -4287,7 +4323,7 @@ \subsubsection{Real-time markets}\label{real-time-markets}}
linearly ramp between one dispatch target and the next, the dispatch
process implicitly ``procures'' some flexibility to manage variability
(\protect\hyperlink{ref-australianenergymarketoperatorDispatchStandardOperating2019}{Australian
-Energy Market Operator, 2021c};
+Energy Market Operator, 2021d};
\protect\hyperlink{ref-ryanVariableGenerationReserves2014}{Ryan et al.,
2014}). As such, the NEM's dispatch is relatively fast and granular when
compared to short-term electricity markets worldwide
@@ -6239,7 +6275,7 @@ \chapter*{References}\label{references}}
{Limit Advice} - {System Strength} in {SA} and {Victoria}}.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorAEMOVirtualPower2021}{}}%
-Australian Energy Market Operator, 2021d. {AEMO Virtual Power Plant
+Australian Energy Market Operator, 2021e. {AEMO Virtual Power Plant
Demonstrations}, {Knowledge Sharing Report} \#3.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorAmendmentMarketAncillary2021}{}}%
@@ -6248,17 +6284,17 @@ \chapter*{References}\label{references}}
{Draft} report and determination.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorBehaviourDistributedResources2021}{}}%
-Australian Energy Market Operator, 2021e.
+Australian Energy Market Operator, 2021f.
\href{https://aemo.com.au/en/initiatives/major-programs/nem-distributed-energy-resources-der-program/operations/der-behaviour-during-disturbances}{Behaviour
of distributed resources during power system disturbances {Overview} of
key findings}.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorDispatchStandardOperating2019}{}}%
-Australian Energy Market Operator, 2021c. Dispatch {Standard Operating
+Australian Energy Market Operator, 2021d. Dispatch {Standard Operating
Procedure}.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorEnduringPrimaryFrequency2021}{}}%
-Australian Energy Market Operator, 2021f. Enduring primary frequency
+Australian Energy Market Operator, 2021a. Enduring primary frequency
response requirements for the {NEM}.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorFastFrequencyResponse2021}{}}%
@@ -6279,7 +6315,7 @@ \chapter*{References}\label{references}}
Response}) {Rule} 2020: {Status} as at 20 {Jan} 2021.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorNEMEngineeringFramework2021}{}}%
-Australian Energy Market Operator, 2021a. {NEM Engineering Framework}.
+Australian Energy Market Operator, 2021b. {NEM Engineering Framework}.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorOperatingGridHigh2021}{}}%
Australian Energy Market Operator, 2021l.
@@ -6301,7 +6337,7 @@ \chapter*{References}\label{references}}
of the {Reliability And Emergency Reserve Trader}.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorQuarterlyEnergyDynamics2021}{}}%
-Australian Energy Market Operator, 2021b. Quarterly {Energy Dynamics Q3}
+Australian Energy Market Operator, 2021c. Quarterly {Energy Dynamics Q3}
2021.
\leavevmode\vadjust pre{\hypertarget{ref-australianenergymarketoperatorShortTermReserve2021}{}}%
@@ -6499,6 +6535,10 @@ \chapter*{References}\label{references}}
{State}/{Territory} {[}WWW Document{]}. URL
\url{https://pv-map.apvi.org.au} (accessed 5.23.2022).
+\leavevmode\vadjust pre{\hypertarget{ref-bagginiHandbookPowerQuality2008}{}}%
+Baggini, A., 2008. Handbook of {Power Quality}. {John Wiley \& Sons,
+Ltd}, {Chichester, UK}. \url{https://doi.org/10.1002/9780470754245}
+
\leavevmode\vadjust pre{\hypertarget{ref-banshwarInternationalExperienceTechnical2018}{}}%
Banshwar, A., Sharma, N.K., Sood, Y.R., Shrivastava, R., 2018. An
international experience of technical and economic aspects of ancillary
@@ -6519,11 +6559,20 @@ \chapter*{References}\label{references}}
economics. {Oxford Institute for Energy Studies}.
\url{https://doi.org/10.26889/9781784671600}
+\leavevmode\vadjust pre{\hypertarget{ref-borensteinEconomicsElectricityReliability2023}{}}%
+Borenstein, S., Bushnell, J., Mansur, E., 2023.
+\href{https://haas.berkeley.edu/wp-content/uploads/WP336.pdf}{The
+{Economics} of {Electricity Reliability}}.
+
\leavevmode\vadjust pre{\hypertarget{ref-brooksReviewFrequencyRegulation2019}{}}%
Brooks, A.E., Lesieutre, B.C., 2019. A review of frequency regulation
markets in three {U}.{S}. {ISO}/{RTOs}. Electricity Journal 32, 106668.
\url{https://doi.org/10.1016/j.tej.2019.106668}
+\leavevmode\vadjust pre{\hypertarget{ref-chapmanElectricMachineryFundamentals2011}{}}%
+Chapman, S.J., 2011. Electric {Machinery Fundamentals}. {McGraw-Hill
+Education}.
+
\leavevmode\vadjust pre{\hypertarget{ref-cherevatskiyGridFormingEnergy2020}{}}%
Cherevatskiy, S., Sproul, S., Zabihi, S., Korte, R., Klingenberg, H.,
Buchholz, B., Oudalov, A., 2020.
@@ -6669,6 +6718,10 @@ \chapter*{References}\label{references}}
\href{https://www.climatechangeinaustralia.gov.au/media/ccia/2.2/cms_page_media/799/ESCI\%20Project\%20final\%20report_210721.pdf}{{ESCI
Project Final Report}}.
+\leavevmode\vadjust pre{\hypertarget{ref-elgerdElectricEnergySystems1971}{}}%
+Elgerd, O.I., 1971. Electric energy systems theory: An introduction.
+{McGraw-Hill}, {New York, N.Y}.
+
\leavevmode\vadjust pre{\hypertarget{ref-energyexemplarPLEXOSEnergyMarket2021}{}}%
Energy Exemplar, 2021. {PLEXOS} \textbar{} {Energy Market Simulation
Software} {[}WWW Document{]}. URL
@@ -6827,6 +6880,11 @@ \chapter*{References}\label{references}}
Reserves} in {Southern Region Grid States}. {Deutsche Gesellschaft für
Internationale Zusammenarbeit GmbH}.
+\leavevmode\vadjust pre{\hypertarget{ref-hirthWhyWindNot2016a}{}}%
+Hirth, L., Ueckerdt, F., Edenhofer, O., 2016. Why {Wind Is Not Coal}:
+{On} the {Economics} of {Electricity Generation}. EJ 37.
+\url{https://doi.org/10.5547/01956574.37.3.lhir}
+
\leavevmode\vadjust pre{\hypertarget{ref-hirthBalancingPowerVariable2015}{}}%
Hirth, L., Ziegenhagen, I., 2015. Balancing power and variable
renewables: {Three} links. Renewable and Sustainable Energy Reviews 50,
@@ -6883,6 +6941,11 @@ \chapter*{References}\label{references}}
\url{https://www.ibm.com/au-en/analytics/cplex-optimizer} (accessed
4.13.2022).
+\leavevmode\vadjust pre{\hypertarget{ref-internationalenergyagencyGridScaleStorage2022}{}}%
+International Energy Agency, 2022.
+\href{https://www.iea.org/fuels-and-technologies/energy-storage}{Grid-{Scale
+Storage}}. {IEA}, {Paris}.
+
\leavevmode\vadjust pre{\hypertarget{ref-internationalenergyagencyNetZero20502021}{}}%
International Energy Agency, 2021.
\href{https://iea.blob.core.windows.net/assets/deebef5d-0c34-4539-9d0c-10b13d840027/NetZeroby2050-ARoadmapfortheGlobalEnergySector_CORR.pdf}{Net
@@ -6927,6 +6990,11 @@ \chapter*{References}\label{references}}
Dagle, J., 2002. Frequency {Control Concerns In The North American
Electric Power System}. {Oak Ridge National Laboratory}.
+\leavevmode\vadjust pre{\hypertarget{ref-kirschenFundamentalsPowerSystem2004}{}}%
+Kirschen, D., Strbac, G., 2004. Fundamentals of {Power System
+Economics}: {Kirschen}/{Power System Economics}. {John Wiley \& Sons,
+Ltd}, {Chichester, UK}. \url{https://doi.org/10.1002/0470020598}
+
\leavevmode\vadjust pre{\hypertarget{ref-kristovTaleTwoVisions2016}{}}%
Kristov, L., De Martini, P., Taft, J.D., 2016. A {Tale} of {Two
Visions}: {Designing} a {Decentralized Transactive Electric System}.
@@ -7213,6 +7281,11 @@ \chapter*{References}\label{references}}
control rule changes directions paper.
\url{https://doi.org/10.13140/RG.2.2.11620.50560}
+\leavevmode\vadjust pre{\hypertarget{ref-reboursComprehensiveAssessmentMarkets2009}{}}%
+Rebours, Y., 2009. A {Comprehensive Assessment} of {Markets} for
+{Frequency} and {Voltage Control Ancillary Services}. {The University of
+Manchester}.
+
\leavevmode\vadjust pre{\hypertarget{ref-reboursSurveyFrequencyVoltage2007}{}}%
Rebours, Y.G., Kirschen, D.S., Trotignon, M., Rossignol, S., 2007b. A
{Survey} of {Frequency} and {Voltage Control Ancillary Services} - {Part
diff --git a/source/10_lit_review.md b/source/10_lit_review.md
index ae5d8d9..8811ed9 100644
--- a/source/10_lit_review.md
+++ b/source/10_lit_review.md
@@ -17,8 +17,7 @@ In this literature review, we lay a theoretical foundation for designing efficie
Given the welfare and economic benefits associated with electricity access, many 20^th^ century states constructed large bulk *power systems* to leverage investment & operational economies of scale. These systems sought to efficiently deliver active power (i.e. power that does work) to numerous electricity end-users (*demand* or *loads*) from electricity suppliers ( *generators*) across vast distances. A typical power system configuration is presented in [@fig:elec_supply_chain]. Generators supply the system with alternating current (AC) power either through a direct electromagnetic connection or through a power inverter interface (which converts the direct current, or DC, produced by the generator to AC). AC power is then efficiently transmitted over long distances through a high voltage *transmission* system. As transmission lines approach load centres, voltages are stepped down to make power delivery to the houses and businesses connected to the lower voltage *distribution system* safer [@mastersRenewableEfficientElectric2004].
-{#fig:elec_supply_chain width=100% short-caption="The bulk power system as an electricity supply chain"}
+{#fig:elec_supply_chain width=100% short-caption="The bulk power system as an electricity supply chain"}
### Synchronous and control areas
@@ -28,7 +27,7 @@ A network area that is operated at a (constant) nominal AC frequency is known as
In broad terms, *operating* a power system involves the direction or control of *power system resources* — generators, loads, network elements and energy storage resources (which can act as both a generator and a load). In practice, however, power system operation is inseparable from the economic objective imposed upon SOs: minimise system costs (or under some market paradigms described in [@sec:lit_review-operational_paradigms], maximise the value of trade) whilst 1) continuously maintaining a balance between active power supply & demand and 2) ensuring that system resources & the system itself are operated within their respective technical envelopes [@woodPowerGenerationOperation2014]. The latter constraint implies *stable* & *secure* operation and is a prerequisite for the former constraint, which more-or-less corresponds to *reliable* operation[^1].
-[^1]: Strictly speaking, reliability is typically defined as the ability of generation to supply load requirements to an administratively-set standard.
+[^1]: Strictly speaking, reliability is typically defined as the ability of generation to supply load requirements to an administratively-set standard, which varies across jurisdictions.
Noting that planning & investment have a large bearing on the manner in which a power system is operated (and vice versa), [@fig:power_system_timeframes] presents a high-level overview of power system phenomena and processes, services & markets that are most pertinent to active power balancing in operational timeframes, with those discussed in detail within this thesis highlighted in bold red text.
@@ -44,75 +43,11 @@ As shown in @fig:power_system_timeframes, power system operations is concerned w
3. *Thermodynamic* phenomena are slower still. They encompass chemical fuel conversion & heat transfer processes in boilers. These phenomena occur over multiple timeframes, from seconds to minutes to hours. I will also extend this category to include the dynamic behaviour of the primary energy sources for hydroelectricity and *variable renewable energy* (VRE), which primarily refers to wind and solar photovoltaic (PV) generation.
-### The need for system balance
-
-#### Synchronism
-
-Following synchronisation, generators (e.g. turbines) and loads (e.g.
-motors) that rotate at a speed proportional to the power system
-frequency are known as *synchronous machines*. As shown in
-[\[eq:synch_speed\]](#eq:synch_speed){reference-type="ref"
-reference="eq:synch_speed"}, the *synchronous speed* is dependent on the
-number of poles of the machine and the power system frequency
-[@Grainger1994].
-
-$$N_s = \frac{120f}{P}
- \label{eq:synch_speed}$$
-
-where $N_s$ is the synchronous speed in revolutions per minute, $P$ is
-the number of magnetic poles and $f$ is the electrical frequency in Hz.
-
-Power system frequency control is required for the stable operation of a
-synchronous area. Should synchronous machines be exposed to high RoCoFs
-and sufficiently serious frequency deviations, they may experience
-equipment-damaging vibrations [@Ulbig2014] or suffer from pole slipping
-due to a loss of synchronism [@DGAConsulting2016]. As such, if frequency
-control services are insufficient in their response, *under-frequency
-load shedding* (UFLS) relays or *over-frequency generation shedding*
-(OFGS) relays, and frequency-sensitive equipment protection relays are
-used as emergency frequency control schemes and equipment protection
-measures, respectively
-[@Eto2018; @AustralianEnergyMarketCommission2019].
-
-The activation of these schemes is undesirable, particularly as UFLS is
-reflected in power system reliability metrics. Moreover, the presence
-and configuration of these schemes in the power system means that if
-frequency deviations are sufficiently large, a cascading series of trips
-and faults may aggravate the active power imbalance and lead to power
-system black-out and collapse [@Ulbig2014; @Hartmann2019].
-
-### Threats to system balance
-
-As highlighted in
-[\[eq:swing_area\]](#eq:swing_area){reference-type="ref"
-reference="eq:swing_area"}, the AC frequency of a power system can
-deviate from its nominal value when there is an imbalance between power
-supply and demand in the synchronous area. Active power imbalances are
-the result of power system *variability* and *uncertainty*.
-
-#### Variability
-
-Variability refers to expected or forecast fluctuations in the balance
-of active power supply and demand [@Ela2011]. Sources of variability
-include fluctuations in load, oscillatory active power output from
-synchronous generators and changing weather conditions (e.g. cloud
-cover, wind speed) that may affect the active power output of VRE
-[@Ela2011; @Bloom2017; @Riesz2015a].
-
-#### Uncertainty
-
-Uncertainty refers to unexpected fluctuations in the balance of active
-power supply and demand [@Ela2011]. Power system uncertainty encompasses
-the unanticipated behaviour of generators, loads and network elements.
-This includes unexpected outages (known as *contingency events*) and
-weather forecast errors that lead to VRE generation forecast error
-[@Ela2011; @Riesz2015a]
-
-## Operational paradigms{#sec:lit_review-operational_paradigms}
+### Operational paradigms{#sec:lit_review-operational_paradigms}
Synchronous areas can be subdivided into *control areas*, which are typically demarcated by the network boundaries of separate electric utilities or electricity markets [@Grainger1994; @Elgerd1971]. Within a control area, the control of AC frequency is the responsibility of a system operator.
-### Vertically-integrated
+#### Vertically-integrated
Historically, this configuration enabled economies of scale in both
asset investment and operation to be achieved by electric utilities,
@@ -122,7 +57,7 @@ within a power system and were responsible for the retail of electricity
to the end-user (these regulated monopolies are known as
vertically-integrated utilities) [@Masters2004].
-### Restructuring and the emergence of wholesale electricity markets
+#### Restructuring and the emergence of wholesale electricity markets
In mandatory pool markets, the system operator commits and dispatches
individual generators (and, in some cases, loads) in the day-ahead and
@@ -139,7 +74,7 @@ It should be noted that these processes are not exclusive to mandatory
pool markets and could be used by vertically-integrated utilities to
efficiently schedule resources in the power system [@Grainger1994].
-#### Electricity industry restructuring
+##### Electricity industry restructuring
Beginning in the early 1990s, perceived inefficiencies and overspend by
monopoly electric utilities, advancements in small low-upfront cost gas
@@ -151,9 +86,9 @@ systems was the implementation of a wholesale market for electricity,
where generators compete for the opportunity to supply electricity and
earn revenue through an auction-based mechanism [@Milligan2017].
-#### Electricity market structures and features
+##### Electricity market structures and features
-##### System operator
+###### System operator
In restructured electricity industries, the implementation of wholesale
markets was accompanied by the creation of an independent power system
@@ -169,7 +104,7 @@ Independent System Operators (ISOs) and Regional Transmission Operators
(RTOs) in North America and the Australian Energy Market Operator
(AEMO).
-##### Market models
+###### Market models
The restructuring process proceeded differently across jurisdictions,
resulting in the implementation of different wholesale market
@@ -221,7 +156,7 @@ Reproduced from
-##### Market platforms
+###### Market platforms
Whilst other commodity markets are settled continuously or sequentially,
reliability and security considerations and concerns have led to
@@ -252,86 +187,77 @@ market. This arrangement means that while dispatch is centralised,
participants manage the commitment of their generation portfolio with
the assistance of pre-dispatch forecasts provided by AEMO [@Riesz2016a].
-## Balancing processes and mechanisms
+## Active power balancing
-### Inherent inertial response {#sec:electromech}
-
-Synchronous machines convert electrical energy to mechanical energy, or
-vice versa, through the interacting magnetic fields of the rotor and the
-stator [@Chapman2011ElectricFundamentals]. In a synchronous generator,
-this interaction produces an electromagnetic torque ($T_e$) on the rotor
-that opposes the mechanical torque ($T_m$) supplied by a prime mover
-([4](#fig:synch_torques){reference-type="ref"
-reference="fig:synch_torques"}). From
-[\[eq:swing\]](#eq:swing){reference-type="ref" reference="eq:swing"},
-which is known as the *swing equation*, we can see that if a generator
-is at synchronous speed (i.e. steady state) and there is a transient
-increase in the electrical load of the power system (equivalent to an
-increase in $P_e$), the rotor of a synchronous generator will begin to
-decelerate as its stored kinetic energy is converted to electrical
-energy [@Grainger1994; @Elgerd1971]. When this electromechanical
-response is observed across synchronous machines, the decrease in rotor
-speed will result in a decrease in the synchronous area's AC frequency
-as per [\[eq:synch_speed\]](#eq:synch_speed){reference-type="ref"
-reference="eq:synch_speed"}. The inverse is true for a decrease in
-electrical load - the synchronous area's AC frequency will increase.
-These inherent responses describe a synchronous machine's *inertial
-response*. $$J\omega_{sm}\frac{d\omega_{sm}}{dt} = P_m - P_e
- \label{eq:swing}$$
-
-where $\omega_{sm}$ is the rotor shaft velocity, $J$ is moment of
-inertia of the rotor, $P_m$ is mechanical power due to $T_m$ and $P_e$
-is electrical power due to $T_e$.
-
-{#fig:synch_torques width="60%"}
-
-#### Active power imbalance and RoCoF
-
-We arrive at the relationship between the active power imbalance
-($P_{gen}-P_{load}$) in a power system and AC frequency in
-[\[eq:swing_area\]](#eq:swing_area){reference-type="ref"
-reference="eq:swing_area"} by extending the dynamics of the swing
-equation from a single synchronous generator to all synchronous
-generators in the synchronous area [@Tamrakar2017].
-[\[eq:swing_area\]](#eq:swing_area){reference-type="ref"
-reference="eq:swing_area"} demonstrates that the rate of change of
-frequency (*RoCoF*) is proportional to the active power imbalance and
-inversely proportional to the system's inertia constant, $H$.
-[\[eq:swing_area\]](#eq:swing_area){reference-type="ref"
-reference="eq:swing_area"} is primarily concerned with synchronous
-generators, not loads, as the rotors of the former store more kinetic
-energy due to a larger physical mass and higher rotational speeds
-[@Ulbig2014; @Denholm2020].
-$$\frac{2H}{f}\frac{df}{dt} = \frac{P_{gen}-P_{load}}{S_{g, total}}
- \label{eq:swing_area}$$ where $H$ is the inertia constant of the
-synchronous area ($H=\sum_{g} H_g$, where
-$H_g = \frac{J_g \omega^2}{2S_g}$), $f$ is the AC frequency,
-$\frac{df}{dt}$ is the rate of change of frequency or RoCoF,
-$S_{g,total}$ is the total apparent power of synchronous generators, and
-$P_{gen}$ and $P_{load}$ are the system's total power supply and total
-power demand (including losses), respectively.
-
-### Load damping response {#sec:load_damp}
-
-Another inherent electromechanical response is that of
-frequency-dependent loads, which include machinery driven by induction
-motors [@AustralianEnergyMarketOperator2019l]. The power consumption of
-frequency-dependent loads decreases with lower frequencies and increases
-with higher frequencies. This is known as *load damping*, as the
-response reduces the imbalance in active power supply and demand and
-hence dampens the change in AC frequency as described in
+In theory, *active power balancing* is simply a consequence of the law of conservation of energy: the energy supplied through primary energy conversion or by energy storage into a network node is equal to the sum of the energy dissipated, stored and consumed at the same network node at each and every moment. In practice, however, it involves the **_moment-to-moment control_ of generation and loads to balance active power supply and demand _across the power system_**. *Moment-to-moment control* is required because it is still uneconomical in many jurisdictions to store electricity at scale (i.e. in the same order of magnitude as generation and demand) despite grid-scale storage cost reductions [@internationalenergyagencyGridScaleStorage2022], and though electricity can be transported close to the speed of light across the network, balancing required coordination *across the power system* because of transmission losses and network constraints imposed by line thermal limits, stability requirements & Kirchoff's circuit laws [@kirschenFundamentalsPowerSystem2004; @hirthWhyWindNot2016a].
+
+### Why is it required?
+
+Unlike the transportation networks of many other commodities, an imbalance between active power supply & demand can lead to deviations in technical parameters — voltage and frequency — that not only have the potential to damage equipment connected to the power system, but also to trigger a system collapse [@borensteinEconomicsElectricityReliability2023]. As such, maintaining active power balance is essential to proper resource and system functioning.
+
+#### The relationship between active power balance & AC frequency
+
+Because synchronous machines are present in most power systems, system active power balance is closely tied to the system's AC frequency. During steady state operation, synchronous machines rotate at a *synchronous speed* ($N_s$) that is proportional to the nominal system frequency ($f$) ([@eq:synch_speed]) [@chapmanElectricMachineryFundamentals2011]:
+
+$$N_s = \frac{120f}{P} \label{eq:synch_speed}$$
+
+where $N_s$ is the synchronous speed in revolutions per minute, $P$ is the number of (rotor) magnetic poles and $f$ is the electrical frequency in hertz.
+
+The link between active power imbalance and synchronous speed/system frequency can be elucidated by examining synchronous machine dynamics. In a synchronous generator (coal-fired, gas-fired and hydro generators), the interaction between the interacting magnetic fields of the rotor and stator produces an electromagnetic torque ($T_e$) on the rotor that opposes the mechanical torque ($T_m$) supplied by a prime mover (e.g. steam turbine) ([@fig:synch_torques]). [@eq:swing], which is an energy balance variation of what is known as the *swing equation*, shows that if there is a transient increase in the electrical load of the power system (equivalent to an increase in $P_e$ and thus $T_e$), the rotor of a synchronous generator will begin to decelerate as its stored kinetic energy is converted to electrical energy [@graingerPowerSystemAnalysis1994; @elgerdElectricEnergySystems1971].
+
+$$J\omega_{sm}\frac{d\omega_{sm}}{dt} = P_m - P_e \label{eq:swing}$$
+
+where $\omega_{sm}$ is the synchronous machine rotor shaft velocity, $J$ is moment of inertia of the rotor, $P_m$ is mechanical power, $T_m$ is mechanical torque, $P_e$ is electrical power and $T_e$ is electromagnetic torque.
+
+{#fig:synch_torques short-caption="Mechanical and electromagnetic torques on a synchronous generator"}
+
+The relationship between the active power imbalance in a power system ($P_{gen}-P_{load}$) and AC frequency is obtained by extending the dynamics of the swing equation from a single synchronous generator to all synchronous generators in a synchronous area ([@eq:swing_area]). [@eq:swing_area] shows that the rate of change of frequency (*RoCoF*) is proportional to the active power imbalance and inversely proportional to the system's inertia constant, $H$. This form of the swing equation only models the *inertial response* of synchronous generators, and not the *load damping* response offered by (frequency-dependent) induction motor loads. Generation inertial response typically plays a large role in electromechanical system dynamics as the high speed and mass of generator rotors mean that they store significant quantities of kinetic energy [@ulbigImpactLowRotational2014; @denholmInertiaPowerGrid2020].
+
+$$\frac{2H}{f}\frac{df}{dt} = \frac{P_{gen}-P_{load}}{S_{g, total}} \label{eq:swing_area}$$
+
+where $H$ is the inertia constant of the synchronous area ($H=\sum_{g} H_g$, where $H_g = \frac{J_g(2\pi f)^2}{2S_g}$), $f$ is the AC frequency, $\frac{df}{dt}$ is the rate of change of frequency or RoCoF, $S_{g,total}$ is the total apparent power of synchronous generators, and $P_{gen}$ and $P_{load}$ are the system's total power supply and total power demand (including losses), respectively.
+
+[@eq:swing_area] also shows that a power system's AC frequency is an indicator of active power balance [@bagginiHandbookPowerQuality2008]. Insufficient generation will lead to a decrease in system frequency (i.e. negative RoCoF) and oversupply will lead to an increase in system frequency (i.e. positive RoCoF).
+
+#### The consequences of frequency deviations
+
+Serious power system frequency deviations away from the nominal value can have harmful effects. Synchronous machines may experience equipment-damaging vibrations [@ulbigImpactLowRotational2014], and both synchronous machines and transformers can overheat and fail if they operate outside their rated voltage-frequency limits [@kirbyFrequencyControlConcerns2002]. Synchronous machines are also vulnerable to damage from high RoCoFs due to pole slipping [@dgaconsultingInternationalReviewFrequency2016]. For these reasons, frequency-sensitive relays are often used to protect power system resources from frequency excursions.
+
+However, these same protection measures can also trigger the complete collapse of the power system. Should the disconnection of a resource following a relay trip exacerbate an existing active power imbalance, the system frequency may deviate further and result in further disconnections. Situations such as these are known as *cascading failures* and can lead to a total system collapse (a *blackout*). Blackouts can have devastating social & economic consequences and require long & complex system restoration procedures before the power system can be returned to normal operation [@kirschenFundamentalsPowerSystem2004]. As such, SOs often employ emergency frequency control schemes that trip loads in the event of under-frequency (*under-frequency load shedding* or *UFLS*) or generation in the event of over-frequency (*over-frequency generation shedding* or *OFGS*) as a last line of defence against frequency-driven system collapse [@australianenergymarketoperatorEnduringPrimaryFrequency2021; @hartmannEffectsDecreasingSynchronous2019].
+
+### Threats to system balance
+
+As highlighted in
[\[eq:swing_area\]](#eq:swing_area){reference-type="ref"
-reference="eq:swing_area"} [@Denholm2020]. However, load damping is
-diminishing in power systems around the world as a growing share of load
-is coupled to the power system through power electronic controllers,
-which enable loads to operate independently of the power system
-frequency [@Undrill2018].
+reference="eq:swing_area"}, the AC frequency of a power system can
+deviate from its nominal value when there is an imbalance between power
+supply and demand in the synchronous area. Active power imbalances are
+the result of power system *variability* and *uncertainty*.
-## The role of frequency control services
+#### Variability
+
+Variability refers to expected or forecast fluctuations in the balance
+of active power supply and demand [@Ela2011]. Sources of variability
+include fluctuations in load, oscillatory active power output from
+synchronous generators and changing weather conditions (e.g. cloud
+cover, wind speed) that may affect the active power output of VRE
+[@Ela2011; @Bloom2017; @Riesz2015a].
+
+#### Uncertainty
+
+Uncertainty refers to unexpected fluctuations in the balance of active
+power supply and demand [@Ela2011]. Power system uncertainty encompasses
+the unanticipated behaviour of generators, loads and network elements.
+This includes unexpected outages (known as *contingency events*) and
+weather forecast errors that lead to VRE generation forecast error
+[@Ela2011; @Riesz2015a]
+
+## Balancing processes and mechanisms
+
+Power system frequency control is required for the stable operation of a
+synchronous area. lianEnergyMarketCommission2019]. Trigger of emergency control schemes is undesirable as it affects reliability utcomes
+
+### The role of frequency control services
As discussed in [2.4](#sec:scuc_sced){reference-type="ref"
reference="sec:scuc_sced"}, SCED is executed by vertically-integrated
@@ -344,7 +270,7 @@ are used by the system operator to manage both small and large
instantaneous active power imbalances that may arise due to variability
and uncertainty.
-## Conventional frequency control scheme and services {#sec:conventional_freq_control}
+### Conventional frequency control scheme and services {#sec:conventional_freq_control}
Power system operators typically employ a hierarchical and sequential
control scheme to contain AC frequency within as narrow a band as
@@ -371,7 +297,7 @@ provided. Source:
@AustralianEnergyMarketOperator2020l.](source/figures/freq_control-03.png){#fig:freq_control
width="\\textwidth"}
-### Inertial response
+#### Inertial response
As discussed in [3.3.1](#sec:electromech){reference-type="ref"
reference="sec:electromech"}, synchronous machines have an inherent
@@ -383,7 +309,7 @@ event (see [\[eq:swing_area\]](#eq:swing_area){reference-type="ref"
reference="eq:swing_area"}) and the speed at which the power system can
be returned to the nominal frequency [@Ulbig2014; @Hartmann2019].
-### Primary frequency control
+#### Primary frequency control
The aim of primary frequency control (PFC) is to arrest the frequency
deviation through the autonomous response of generators and
@@ -405,7 +331,7 @@ small (tight dead-band) or contingency (wide dead-band) imbalance events
and should ideally be sustained until secondary frequency control can
take over [@Eto2018].
-### Secondary frequency control
+#### Secondary frequency control
Secondary frequency control (SFC) replaces PFC and can consist of either
or both of a synchronous area secondary control system known as an
@@ -433,7 +359,7 @@ governor, moving the droop characteristic to $L_1$ and returning the
system to frequency $\omega_0$. Source:
@Wang2003.](source/figures/droop.png){#fig:droop width="75%"}
-### Tertiary frequency control
+#### Tertiary frequency control
Tertiary frequency control (TFC) is intended to replace PFC and SFC. TFC
is typically used as a margin of safety in systems where relatively
@@ -442,7 +368,7 @@ correct an active power imbalance [@Hewicker2020]. Some systems, such as
the NEM, do not procure TFR and instead rely solely upon a SCED that is
frequently executed [@Billimoria2020].
-### Dispatch and unit commitment
+#### Dispatch and unit commitment
#### Security-constrained economic dispatch
@@ -489,11 +415,10 @@ determining whether it is profitable to provide energy (e.g.
hydroelectric power plants, battery energy storage systems)
[@Wood2014; @Cadwalader1998ReliabilityPricing].
-### Longer-term scheduling
+#### Longer-term scheduling
-## Emerging challenges in power system operations
-
-### Inverter-based resources and frequency control {#sec:ibr_freq}
+### Emerging challenges
+#### Inverter-based resources and frequency control {#sec:ibr_freq}
Inverter-based resources (IBR) include variable IBR (solar PV and Type
III and Type IV wind turbines [@Wu2018]), BESS and high voltage direct
@@ -503,8 +428,8 @@ of particular interest to system operators and market designers as many
power systems are currently experiencing high instantaneous penetrations
of variable IBR (in excess of 50%) and because many more are expected to
do so in the future [@AustralianEnergyMarketOperator2019; @IRENA2020].
-
-### Challenges posed by inverter-based resources
+
+##### Challenges posed by inverter-based resources
High penetrations of IBR in power systems pose challenges to frequency
control due to their characteristics, particularly in islanded power
@@ -512,7 +437,7 @@ systems or weakly-interconnected control areas that cannot rely on a
wider synchronous area for frequency control services [@Hodge2020].
These include [@Kroposki2019]:
-#### Interface to power system
+###### Interface to power system
As IBR interface to a synchronous area through inverters, they are not
electromagnetically coupled to the power system and therefore do not
@@ -525,7 +450,7 @@ frequency nadirs or zeniths and the tripping of emergency protection
schemes that would otherwise not occur in high inertia systems
[@Machowski2020; @Ulbig2014; @Hartmann2019; @Dreidy2017].
-#### Variability and uncertainty
+###### Variability and uncertainty
The aggregate degree of power system variability and uncertainty is
likely to increase with higher penetrations of variable IBR
@@ -542,7 +467,7 @@ particularly distributed energy resources such as rooftop solar PV and
electric vehicles
[@AustralianEnergyMarketOperator2020d; @Wurth2019; @AustralianEnergyMarketOperator2020m].
-### Provision of frequency control services
+##### Provision of frequency control services
The presence of synchronous machines and grid-following inverters makes
inertial response and frequency control necessary for secure and stable
@@ -558,7 +483,7 @@ active power, within the constraints of primary or stored energy, to
provide what is known as *fast frequency response* (FFR)
[@Machowski2020; @Hodge2020].
-#### Fast frequency response
+###### Fast frequency response
FFR can generally be provided within a matter of milliseconds to provide
a sustained active power response similar to PFC or to mitigate high
@@ -585,7 +510,8 @@ synchronous machine to some degree within an inverter control system
measurement and is not inherent, it cannot be considered to be a direct
substitute for inertial response [@Miller2017; @AEMO2017a].
-## Procurement of frequency control services {#sec:procurement}
+### Designing operational practices
+#### Procurement of frequency control services {#sec:procurement}
As highlighted by @Ela2012b and @Billimoria2020, frequency control
services are typically procured through a combination of market-based
@@ -593,9 +519,9 @@ mechanisms, such as remunerative schemes or contract or spot markets,
and regulatory mechanisms, such as connection requirements or system
operator intervention.
-### Market-based mechanisms {#sec:market_mech}
+##### Market-based mechanisms {#sec:market_mech}
-#### Suitability of markets
+###### Suitability of markets
Many restructured electricity industries have developed competitive
*ancillary services* markets that enable frequency control services to
@@ -615,7 +541,7 @@ system costs, incentivising frequency control provision and improving
trade outcomes for market participants by *co-optimising* markets for
energy and frequency control services [@Ela2016].
-#### Opportunity costs and co-optimisation
+###### Opportunity costs and co-optimisation
To provide raise frequency control services, generation must allocate
reserve capacity, which may be at the expense of profitable energy
@@ -643,7 +569,7 @@ electricity markets:
profit for market participants whilst minimising overall costs to
the system [@Ela2012a; @IntelligentEnergySystems2010a].
-#### Potential benefits of market-based mechanisms
+###### Potential benefits of market-based mechanisms
Compensation for frequency control services addresses the externality of
providing ancillary services, particularly if the compensation is
@@ -657,13 +583,13 @@ control capabilities by market participants into the future (*dynamic*
efficiency)
[@Thorncraft2007; @Riesz2015b; @Biggar2014TheMarkets; @AustralianEnergyMarketCommission2020a].
-#### Challenges in frequency control services markets {#sec:challgnes_fcas_markets}
+##### Challenges in frequency control services markets {#sec:challgnes_fcas_markets}
Frequency control services markets face both existing and emerging
challenges to achieving productive and dynamically efficient outcomes.
The main challenges being faced in these markets are outlined below:
-##### Product design and fungibility.
+###### Product design and fungibility.
Products in existing frequency control services markets generally
reflect the capabilities and requirements of conventional frequency
@@ -694,7 +620,7 @@ frequency response [@Ela2012b], a market may not deliver a net benefit
if there is limited competition or the costs and complexity of
administering a market are significant [@Rebours2007b; @Ela2019].
-##### Price formation.
+###### Price formation.
Price formation is an unresolved issue within frequency control services
market design. Ideally, the price of provision should be explicit,
@@ -719,7 +645,7 @@ and dynamically efficient market outcomes:
and inseparable from other system security products
[@Billimoria2020; @EnergySecurityBoard2020].
-##### Cost allocation.
+###### Cost allocation.
In many mandatory pool markets, the cost of frequency control services
procured by the system operator is allocated to loads, even though the
@@ -739,7 +665,7 @@ based on a 'User Pays' framework, whereby power system resources that
impose frequency zenith, nadir or RoCoF limits pay for frequency control
services [@AustralianEnergyMarketCommission2020a].
-##### IBR participation.
+###### IBR participation.
IBR cannot or do not participate in many frequency control services
markets. Historically, literature has focused on the impact of variable
@@ -761,7 +687,7 @@ security requirements change over time and as high instantaneous IBR
penetrations are often associated with low energy prices
[@Ela2019; @EnergySecurityBoard2020].
-### Regulatory mechanisms {#sec:regulatory_mech}
+##### Regulatory mechanisms {#sec:regulatory_mech}
Regulatory mechanisms, such as equipment technical standards, grid codes
and system operator intervention, were used by monopoly electric
@@ -772,7 +698,7 @@ market-based mechanisms to procure frequency control services. In fact,
the processes of designing and regulating market rules are in and of
themselves regulatory mechanisms [@Sioshansi2006].
-#### Potential benefits of regulatory mechanisms
+###### Potential benefits of regulatory mechanisms
Regulatory mechanisms are ideal for mandating basic frequency control
capabilities as a condition for access or where markets may be difficult
@@ -781,7 +707,7 @@ power, oversupply of a product or the issues discussed in
[6.1.4](#sec:challgnes_fcas_markets){reference-type="ref"
reference="sec:challgnes_fcas_markets"} [@Ela2012b].
-#### Shortfalls of regulatory mechanisms
+###### Shortfalls of regulatory mechanisms
It may be difficult for regulatory mechanisms to ensure that sufficient
frequency control services can be procured in power systems and
@@ -798,7 +724,7 @@ every 5 years [@AustralianEnergyMarketCommission2018], a timeframe in
which the solar PV capacity installed in the NEM has more than tripled
(2014-2019) [@AustralianPVInstitute].
-#### Regulatory requirements as a solution to market failures
+###### Regulatory requirements as a solution to market failures
Regulatory mechanisms are being increasingly used in power system
jurisdictions where frequency control services markets have failed to
@@ -825,14 +751,14 @@ may play, how they interact with market-based mechanisms and the
relative benefits and costs of further frequency control services
marketisation, both now and into the future.
-## Designing frequency control arrangements {#sec:designing_arrangements}
+### Designing frequency control arrangements {#sec:designing_arrangements}
Designing frequency control arrangements is a control, regulatory and
market design problem which has become more complex in recent years due
to electricity industry restructuring and growing penetrations of IBR
[@VanderVeen2016].
-### Outcomes of good design
+#### Outcomes of good design
It is important to define desired outcomes of the design process. Below,
we present three outcomes that have previously been proposed for
@@ -860,7 +786,7 @@ control arrangements) by @Rebours2007b and the
these arrangements, such as the energy market and other ancillary
services markets.
-### Complexity of the design process
+#### Complexity of the design process
Designing frequency control arrangements is a complex exercise in
managing interrelated and interacting capabilities, mechanisms and
@@ -894,7 +820,7 @@ control services provided, and economic objectives, which relate to the
productive, dynamic and price and cost-allocation efficiency of the
arrangements.
-#### Interactions between capability, strategy and performance
+##### Interactions between capability, strategy and performance
These three design layers often interact. Technical capabilities may
guide the design of the control strategy, and therefore the mechanisms
@@ -908,7 +834,7 @@ California and Midcontinent ISOs have introduced ramping products to
address increasing variability and uncertainty in their power systems
[@Ela2016; @Ela2017].
-### Diversity of design outcomes
+#### Diversity of design outcomes
The design process has and will most likely continue to proceed
differently across jurisdictions due to the diversity of both the
@@ -923,7 +849,7 @@ control arrangements across the world have been reviewed and compared
extensively in the literature
[@Rebours2009; @Ela2011; @DGAConsulting2016; @Hewicker2020; @Rebours2007a; @Rebours2007; @Zhou2016; @ReishusConsultingLLC2017; @Banshwar2018].
-### Design principles and considerations
+#### Design principles and considerations
Previous literature has explored the key design considerations for
frequency control arrangements. @Rebours2007b outline design principles
@@ -951,7 +877,7 @@ relatively little attention to the technical capabilities of power
system resources and the design of and interactions between frequency
control products.
-#### Holistic design
+##### Holistic design
@Ela2012b, @Billimoria2020 and @MacGill2020a recognise that power system
frequency control arrangements are typically composed of a mixture of
@@ -964,7 +890,7 @@ required by a power system. This can only be achieved by considering the
interactions, or *interfaces*, between mechanisms within a power
system's frequency control strategy.
-#### Interfaces
+##### Interfaces
The concept of interfaces in electricity industry decision-making is
distinct but coupled to the frequency control arrangement design layers
@@ -975,7 +901,7 @@ market-based mechanisms) and the technical and physical processes and
the requirements of the power system (i.e. frequency control capability
and physical performance) [@Thorncraft2009].
-##### Security decision-making interface.
+###### Security decision-making interface.
The security decision-making interface includes system operator
processes in integrated markets (e.g. SCUC and SCED) which co-optimise
@@ -988,7 +914,7 @@ studies implicitly assume that existing security decision-making
processes and frequency control products are adequate and efficient, and
will therefore perform well.
-#### Interfaces between mechanisms in the frequency control strategy
+###### Interfaces between mechanisms in the frequency control strategy
Interfaces change over time and with technological innovation
[@Thorncraft2009]. The arrival of highly-controllable loads and IBR in
@@ -1000,7 +926,7 @@ process that is separate from physical characteristics and processes
within the frequency control strategy of a power
system.](source/figures/interfaces_03.png){#fig:interfaces}
-##### Interface between control and procurement mechanisms.
+###### Interface between control and procurement mechanisms.
Some literature has begun to explore the interface between control
mechanisms and market-based mechanisms. @Garcia2019a explore the impact
@@ -1013,7 +939,7 @@ synthetic/virtual inertia provision from IBR. However, these studies do
not consider how control mechanisms might interface with other
regulatory mechanisms, such as equipment performance standards.
-##### Interface between procurement mechanisms.
+###### Interface between procurement mechanisms.
In framing the design challenge for power system security services in
the NEM, @MacGill2020, @Billimoria2020 and @Skinner2020 acknowledge that
@@ -1029,6 +955,8 @@ understand how these procurement models might interface with and
integrate into existing and emerging market processes if an optimum for
the entire system is to be achieved [@MacGill2020].
+## Emerging challenges in power system operations
+
## Conclusion
Frequency control is vital to the secure operation of a power system.
diff --git a/source/references.bib b/source/references.bib
index 5382645..d8b1bbf 100644
--- a/source/references.bib
+++ b/source/references.bib
@@ -230,7 +230,7 @@ @article{ainslieSpeciousRewardBehavioral1975
doi = {10.1037/h0076860},
abstract = {In a choice among assured, familiar outcomes of behavior, impulsiveness is the choice of less rewarding over more rewarding alternatives. Discussions of impulsiveness in the literature of economics, sociology, social psychology, dynamic psychology and psychiatry, behavioral psychology, and "behavior therapy" are reviewed. Impulsiveness seems to be best accounted for by the hyperbolic curves that have been found to describe the decline in effectiveness of rewards as the rewards are delayed from the time of choice. Such curves predict a reliable change of choice between some alternative rewards as a function of time. This change of choice provides a rationale for the known kinds of impulse control and relates them to several hitherto perplexing phenomena: behavioral rigidity, time-out from positive reinforcement, willpower, self-reward, compulsive traits, projection, boredom, and the capacity of punishing stimuli to attract attention. (31/2 p ref) (PsycINFO Database Record (c) 2016 APA, all rights reserved)},
keywords = {Impulsiveness,Learning Theory,Literature Review,Self-Control},
- file = {/home/abi/Dropbox/zotero/Ainslie/ainslie_1975_specious_reward.pdf;/home/abi/Zotero/storage/QZ4S7RQ4/1975-27605-001.html}
+ file = {/home/abi/Zotero/storage/QZ4S7RQ4/1975-27605-001.html}
}
@book{akinkunmiIntroductionStatisticsUsing2019,
@@ -2585,6 +2585,15 @@ @report{bonesEnduringPrimaryFrequency2021
file = {/home/abi/Dropbox/zotero/Bones et al/bones_et_al_2021_enduring_primary_frequency_response_-_ct2_–_power_system_operation_and.pdf}
}
+@report{borensteinEconomicsElectricityReliability2023,
+ title = {The {{Economics}} of {{Electricity Reliability}}},
+ author = {Borenstein, Severin and Bushnell, James and Mansur, Erin},
+ date = {2023-03},
+ url = {https://haas.berkeley.edu/wp-content/uploads/WP336.pdf},
+ langid = {english},
+ file = {/home/abi/Dropbox/zotero/Borenstein et al/borenstein_et_al_the_economics_of_electricity_reliability.pdf}
+}
+
@article{borensteinMarketPowerElectricity1999,
title = {Market {{Power}} in {{Electricity Markets}}: {{Beyond Concentration Measures}}},
author = {Borenstein, Severin and Bushnell, James and Knittel, Christopher R.},
-
