2. Existing ASs and Respective Market Design
2.1. Overview of Existing ASs
2.1.1. Frequency Control
- Frequency Containment Reserves (FCRs)/Primary Frequency Control: FCR is the first control action to be activated, usually within 30 s, in a decentralized fashion over the synchronous area.
- Frequency Restoration Reserves (FRRs)/Secondary Frequency Control: FRR is the centralized automated control, activated from the TSO in the time interval between 30 s and 15 min from the imbalance occurrence. FRR can be distinguished in reserves with automatic activation (automatic Frequency Restoration Reserves—aFRR) and reserves with manual activation (manual Frequency Restoration Reserves—mFRR).
- Replacement Reserves (RRs)/Tertiary Frequency Control: RR is a manual control. Typical activation time for RRs is from 15 min after the imbalance occurrence (in Continental Europe) up to hours after.
2.1.2. Voltage Control and Reactive Power Supply
2.1.3. Black-Start Capability/Grid Restoration
2.2. Conventional AS Market Design
2.2.1. Frequency Control
2.2.2. Voltage Support
2.2.3. Black Start
3. New Emerging ASs to Be Offered by DRESs and Procurement Schemes
3.1. New Emerging ASs
3.1.1. Inertial Response
3.1.2. Active Power Ramp Rate Control
3.1.3. Frequency Response ASs and DRESs Participation
3.1.4. Voltage Control and Reactive Power Support
3.1.5. FRT Capability and Fault-Clearing
3.1.6. Harmonics Mitigation
3.2. Suggested Procurement Schemes in Distribution Grids
3.2.1. AS in Smart Grids and Microgrids
3.2.2. Integration of ESS and EVs for Providing AS
4. Market Tools and Mechanisms
4.1. Electricity Market at Distribution Grid Level
- Centralized AS market model: there is a common market for resources connected both at distribution and transmission grid level, without any participation from the DSO.
- Local AS market model: there is a local market operated by the DSO concerning the resources at distribution grid level. After the market closure, the DSO makes the proper aggregation in order to bid the remaining in AS market, operated by the TSO.
- Shared balancing responsibility model: Each operator (DSO and TSO) operates separately at each network the balancing responsibilities. Therefore, there is a local market at DSO with a pre-agreed power exchange schedule with the TSO, while the resources at distribution grid cannot bid their offers directly to the TSO. The pre-agreed schedule can be determined by considering the results of the spot markets, which are defined as energy-only markets, or alternatively by using the past forecasts at each common point of connection between DSO-TSO.
- Common TSO-DSO AS market model: In this model, both operators (TSO and DSO) share the common target of decreasing the overall operational cost of the resources. This aim can be achieved by operate jointly a single market (namely central variant). Another approach proposes the dynamic integration of a decentralized DSO market (namely the local market) and a central TSO market (namely decentralized variant).Central variant: A single market session is operated, where all bids are offered and cleared considering both distribution and transmission constraints.Decentralized variant: initially, a local market operated by the DSO for local needs takes place by considering the grid constraints at distribution grid level. Consequently, all local markets interact with the central TSO market.
- Integrated flexibility market model: In the final market configuration, a more liberate market structure is proposed, where both Operators (TSOs, DSOs) and other market participants (such as balancing responsible parties) can participate in order to fulfil their needs. However, an unbiased market operator is needed for ensuring neutrality. Therefore, in this case, AS markets and intraday markets can difficulty be discretized.
4.2. Ideas for Incentives to DRESs for Participation in AS Markets
5. Obstacles and Barriers
5.1. Technical Barriers
5.2. Regulatory Barriers
5.3. Financial Barriers
5.4. Potential Barriers Regarding the New Emerging ASs
- Inertial response: The quantification of the inertial response faces a number of challenges. (i) Inertial response is actually detectable only in cases of large ROCOFs, i.e., under major frequency events. Thus, for most of the time, the inertial response results in power deviations of the DRESs’ electrical power that are too small to be measured. On the other hand, inertial response is present all the time helping the system to arrest large frequency deviations. (ii) If we assume the realistic case where the various DRES within a distribution system have different inertia constants, the quantification of the aggregated inertial response, as seen at POI of the distribution-transmission system is still an open research issue. (iii) The term “inertial response” is currently used also for the action of FFR. Such a response is provided by DRES that are not associated with a fast ESS (e.g., supercapacitor or flywheel). Therefore, it is actually a late inertial response, for which the measurement of frequency and ROCOF is required. The latter, in turn, poses challenges with respect to the accurate quantification of this service.
- PFR: Until now, SG units are paid for their capacity offers and in some cases for the energy injected when providing the service . A key challenge is highlighted in reference , which examines the participation of DRES in PFR by proposing a novel procedure to design the frequency droop curves, in an attempt that every distribution feeder provides a guaranteed frequency response at the feeder head (transmission–distribution interface). However, a concern arises regarding the contribution of every single unit to the service so that they are not unfairly penalized and inject the required power to the system based on their ratings and their location in the distribution network. If such behavior can be achieved, an additional solution should be found in terms of remunerating the aggregated service provided to the TSO and distributing the payments to the individual DRES/BESS providers. Those payments should be based on the power output of every unit, as indicated by a proper measuring system, in accordance to what was previously referred.
- Voltage regulation: Several technical problems during voltage regulation with reactive power are identified, such as (i) technical capability of providing the required reactive power characteristic; (ii) impedances of the DG plant components are not sufficiently considered during the planning operation of the DG; and (iii) the requested reactive power is provided at connection terminals of the DG units and not at PCC of the entire DG . Therefore, apart for deriving a proper definition and metric for the reactive power, the reactive power capability of the converter-interfaced DRESs should also be properly evaluated. Also, this particular AS adds costs to converter-interfaced DRESs, due to the active power losses within the converter and the step-up transformers (whenever they exist), leading to a reduction in the overall efficiency . These costs should be taken into account and compensated.
- Power smoothing/ramp-rate control: Currently, power smoothing is not recognized as an AS by most grid operators. However, in some cases of islanded and RES-heavy power systems, grid codes define maximum variability level of DRES, typically in terms of ramp rates, hence regard power smoothing as a system support function . The development of this service highly depends on the deployment of ESS technologies. Therefore, any obstacle preventing their usage in order to provide additional flexibilities, especially within the distribution networks, can also be regarded as an obstacle for power smoothing. In reference , the installation and control of ESS for reducing the variability of PV units is considered to significantly raise to their operating cost as well as the cost of their produced power. Such costs can be recovered only if power smoothing is provided as an AS and a relevant market is introduced. Also, since mainly TSOs are going to take advantage of the service’s benefits, because of the reduction in the number of units in reserve when power smoothing is provided, a relevant market needs to be introduced at the transmission system level, in parallel with the market for PFR procurement.
- FRT and fault clearing: An important challenge of the fault participation of DRES units regards the fault current limitation, which is imposed in most of the converter-interfaced DRES because of the thermal limits of the switching devices. Therefore, the use of the conventional over-current protection techniques cannot be facilitated . Hence, the capability of the converter to provide fault-currents should be also evaluated. If converters are oversized to meet this demand, additional costs will arise for the producers that should be taken into account when providing the service. Finally, the benefit of making the DRES inject certain currents during the fault period so that the selectivity of the existing protection means is preserved even under very large DRES penetration should be accordingly evaluated.
- Harmonic mitigation: The idea for the injection of certain harmonic currents in order to mitigate the voltage harmonic pollution at specific nodes within the distribution system is not applicable until now, since several international standards establish particular harmonic current limits to the connecting facilities, as a way to mitigate voltage harmonics. This may be required either directly, as in the case of IEEE Std. 519–2014 [154,155] or indirectly, by setting voltage harmonic limits, which in combination with the system impedance lead to the respective current limits (e.g., IEC 61000-3-6 Std. ). It is evident from the review conducted in the previous section that harmonic mitigation by DRES is already considered in the literature as possible ASs. Therefore, the particular standards need to be revised in order to allow some of the DRESs to act like active harmonic filters. Finally, the additional cost incurred for making a DRES operate as an active filter is not yet addressed.
6. Suggestions and Conclusions
- The DRES within the distribution grids can provide a number of traditional and new AS, thus enabling the decommitment of conventional SG, mostly driven by fossil fuels while maintaining the secure and stable operation of the power system.
- A number of obstacles and barriers need to be overcome for the introduction of AS originating from the DRESs. First, a number of technical and economic issues need to be researched as mentioned in the four suggestions above, particularly the measurement and quantification of the new services so that they cease to be treated as system-support functions and start to be treated as tradable ASs.
- Each of the aforementioned suggestions presents a research topic that involves, apart from researchers, regulatory authorities, and standardization bodies.
- The list of the ASs presented in Figure 6 is not exhaustive but simply presents those ASs treated in the EASY-RES project. Additional services may be defined (for instance, congestion management) which however need to be properly delimited in order to be treated as future ASs.
Conflicts of Interest
|Austria||Generators/Load/Pump Storage/Batteries ≤ 1 MW||1 MW < Generators/Load/Pump Storage ≤ 5 MW||Generators/Load/Pump Storage ≤ 1 MW||No|
|Belgium||Generators/Load/Pump Storage ≤ 1 MW||Generators/Load/Pump Storage ≤ 1 MW||Generators/Load/Pump Storage ≤ 1 MW||No|
|Bosnia and Herzegovina||Generators only (no minimum)||1 MW < Generators only ≤ 5 MW||5 MW < Generators/Load ≤ 10 MW||No|
|Croatia||Generators only (no minimum)||Generators only ≤ 1 MW||Generators/Pump Storage ≤ 1 MW||No|
|Czechia||1 MW < Generators only ≤ 5 MW||1 MW < Generators/Load ≤ 5 MW||1 MW < Generators/Load/Pump Storage ≤ 5 MW||No|
|Denmark||Generators/Load/Batteries ≤ 1 MW||1 MW < Generators/Load ≤ 5 MW||5 MW < Generators/Load ≤ 10 MW||No|
|Finland||Generators/Load/Batteries ≤ 1 MW||1 MW < Generators only ≤ 5 MW||1 MW < Generators/Load ≤ 5 MW||No|
|France||Generators/Load/Pump Storage/Batteries ≤1 MW||Generators/Pump Storage ≤ 1 MW||5 MW < Generators/Load/Pump Storage ≤ 10 MW||5 MW < Generators/Load/Pump Storage ≤ 10 MW|
|Germany||1 MW < Generators/Load/Pump Storage/Batteries ≤ 1 MW||1 MW <Generators/Load/Pump Storage ≤ 5 MW (90 s < t ≤ 5 min)||1 MW <Generators/Load/Pump Storage ≤ 5 MW (5 min < t ≤ 15 min)||No|
|Great Britain||Generators/Load/Pump Storage/Batteries ≤ 5 MW||No||5 MW < Generators/Load/Pump Storage/Batteries ≤ 10 MW||1 MW < Generators/Load/Pump Storage ≤ 5 MW|
|Greece||Generator only ≤ 1 MW||Generators only ≤ 1 MW||Generators only||No|
|Hungary||Generators only ≤ 1 MW||Generators only ≤ 1 MW||No||Generators/Load ≤ 1 MW|
|Ireland||1 MW < Generators/Load/Pump Storage/Batteries ≤ 5 MW||No||Generators/Load/Pump Storage ≤ 1 MW||No|
|Latvia||−||No||Generators only ≤1 MW||No|
|Lithuania||−||No||Generators/Pump Storage (no minimum)||Generators/Load/Pump Storage ≤ 1 MW|
|Netherlands||1 MW < Generators/Load/Batteries ≤ 5 MW||1 MW < Generators/Load/Batteries ≤ 5 MW (t ≤ 90 s)||5 MW < Generators/Load ≤ 10 MW||No|
|Norway||Generators only ≤ 1 MW||5 MW < Generators only ≤ 10 MW||Generators/Load ≤ 1 MW||No|
|Poland||Generators only ≤ 1 MW||Generators only ≤ 1 MW||No||−|
|Portugal||Generators only (no minimum)||Generators only > 10 MW (90 s < t ≤ 5 min)||> 10 MW||≤ 1 MW|
|Romania||1 MW < Generators only ≤ 5 MW||Generators only > 10 MW||1 MW < Generators only ≤ 5 MW||1 MW < Generators only ≤ 5 MW|
|Serbia||1 MW < Generators only ≤ 5 MW||Generators only ≤ 1 MW||Generators/Pump Storage ≤ 1 MW||No|
|Slovakia||Generators only ≤ 1 MW||1 MW < Generators only ≤ 5 MW||1 MW < Generators/Load/Pump Storage ≤ 5 MW||No|
|Slovenia||Generators only (no minimum)||Generators/Pump Storage ≤ 1 MW (5 min < t ≤ 15 min)||Generators/Load/Pump Storage ≤ 1 MW (5 min < t ≤ 15 min)||No|
|Spain||Generators only (no minimum)||Generators only > 10 MW (90 s < t ≤ 5 min)||Generators/Pump storage > 10 MW (5 min < t ≤ 15 min)||Generators/Pump Storage > 10 MW (20 min < t ≤1 h)|
|Sweden||Generators only ≤ 1 MW||1 MW < Generators only ≤ 5 MW||5 MW < Generators/Load ≤ 10 MW||No|
|Switzerland||Generators/Load/Pump Storage/Batteries ≤ 1 MW||1 MW < Generators/Load/Pump Storage/Batteries ≤ 5 MW||1 MW < Generators/Load/Pump Storage/Batteries ≤ 5 MW||1 MW < Generators/Load/Pump Storage/Batteries ≤ 5 MW|
|Austria||Mandatory for power plants in transmission system||Generators/DSO/Wind farms/DSO connected units/Transformers||Transmission/Distribution||Partly|
|Belgium||No mandatory. All Generating units > 25 MVA must be capable of voltage control||Generators/Wind farms/Transformers||Transmission||Yes|
|Bosnia and Herzegovina||Mandatory||Generators||Transmission||No|
|Croatia||All power plants||Generators/Wind farms/Transformers||Transmission/Distribution||Yes|
|Czechia||All units connected at 220 kV +||Generators/Transformers||Transmission||Yes|
|Estonia||Mandatory for all plants connected to the main grid||Generators/Wind farms/HVDC/Transformers||Transmission/Distribution||−|
|Finland||Mandatory for all power plants||Generators/Wind farms/DSO connected units/Transformers||Transmission/Distribution||No|
|France||Mandatory primary voltage control for all units at transmission level and secondary voltage regulation for all units connected at > 225 kV||Generators/Wind farms/PV/HVDC||Transmission/Distribution||Partly|
|Germany||Voltage control requirements for plants in both high- and medium-voltage||Generators/Wind farms/HVDC/DSO connected units/Transformers||Transmission/Distribution||Partly|
|Great Britain||Mandatory for all conventional generators and wind farms connected to transmission.||Generators/Transformers||Transmission/Distribution||Yes|
|Greece||Production units (except RES) > 2 MW (comply with technical regulation)||Generators/Transformers||Transmission||No|
|Hungary||All power plants > 50 MW connected to transmission grid or 132 kV||Generators/Transformers||Transmission/Distribution||Yes|
|Italy||Mandatory for power units ≥ 10 MVA||Generators/Transformers||Transmission||No|
|Latvia||Power plants||Generators/ Wind farms/Transformers||Transmission||No|
|Lithuania||All power plants in transmission||Generators/ Wind farms/HVDC/Transformers||−||Partly|
|Netherlands||Mandatory for generators > 5 MW. It is a contracted service||Generators/DSO/ Industrial consumers/Wind farms/PV/HVDC/DSO connected units/Transformers||Transmission/Distribution||Partly|
|Norway||All powerplants||Generators/DSO/Industrial consumers/Wind farms/HVDC/DSO connected units/Transformers||Transmission/Distribution||Yes|
|Poland||All Generating Units and also centrally dispatched units contracted for this service||Generators/ Wind farms/DSO connected units/Transformers||Transmission/Distribution||Yes|
|Portugal||All conventional generators||Generators||Transmission||No|
|Serbia||Mandatory for all power plants in transmission grid||Generators/Transformers||Transmission||Yes|
|Slovakia||Mandatory primary voltage control, secondary voltage control as a paid service at transmission level (400 kV and 220 kV)||Generators/Transformers||Transmission||Yes|
|Spain||Mandatory service for all power plants > 30 MW connected to the transmission grid||Generators/DSO/ Industrial consumers/Wind farms/PV/HVDC/DSO connected units/Transformers||Transmission/Distribution||No|
|Switzerland||All power plants connected to transmission grid with available reactive power and without compromising the active power||Generators/DSO/Transformers||Transmission/Distribution||Yes|
|Country||Mandatory||Voltage Level||Paid by TSO||Regulated Gradient for the BS Unit|
|Austria||Hydro storage power plants. Not mandatory for power plants||Transmission||Yes||No|
|Belgium||Not mandatory, provided from gas power plant and pumped storage.||Transmission||Yes||No|
|Bosnia and Herzegovina||Mandatory||Transmission||No||−|
|Croatia||Mandatory for plants determined by defense plan||Transmission/Distribution||No|
|Czechia||No obligations to provide black start from any unit||Transmission||Yes||−|
|Denmark||Not mandatory||Transmission||Yes||101 MW–200 MW/15 min|
|Estonia||Not mandatory, provided by power plants included in restoration plan||Transmission||Yes||−|
|Finland||Not mandatory, agreed bilaterally by grid code.||Transmission/Distribution||Yes||No|
|France||Not mandatory, provided by nuclear plants||Transmission/Distribution||No||−|
|Great Britain||Now mandatory. Procured via bilateral contracts with power stations.||Transmission/Distribution||Yes||No|
|Greece||By predefined power plants||Transmission||Yes||−|
|Hungary||Mandatory for power plants > 500 MW connected to transmission grid. Also provided by other plants with BS capability||Transmission/Distribution||Yes||No|
|Ireland||Mandatory for Northern Ireland for certain plant types (Hydro, Pump storage, interconnectors, open cycle gas turbines)||−||−||−|
|Italy||Mandatory for power plants defined in restoration plan||Transmission||No||−|
|Latvia||Agreements with hydro power plants||Transmission||Yes||No|
|Netherlands||Not mandatory, it is a contracted service||Transmission/Distribution||Yes||−|
|Norway||Mandatory for power plants with significant impact on reconstruction of network or other critical functions||Transmission/Distribution||No||No|
|Portugal||Not mandatory, provided by a CCGT 1 and a hydro plant||Transmission||Yes||No|
|Romania||Mandatory for power plants included in black start plan||Transmission||No||No|
|Serbia||Mandatory for Hydro Power Plants||Transmission||Yes||No|
|Spain||Not mandatory, mainly provided by hydro plants||−||No||No|
|Sweden||Contracts with suppliers||Transmission||Yes||−|
|Switzerland||ensure that for the reestablishment of supply after a major incident an adequate number of power stations, qualified for black start and island operation consolidated to a buildup-cell 2, are ready for operation||Transmission||Yes||No|
|1 CCGT = Combined Cycle Gas Turbine|
|2 A buildup-cell is defined as a small subnet, limited in area and electrical network, which consists of one power station equipped with black start facilities and one or more power stations with islanding functionality being able to keep frequency, voltage and power stable in this buildup-cell, with an adequate load at its disposal. |
The buildup-cell needs:
-to have a direct connection to the 220 kV-level
-to be connected to the same or neighboring nodes
-Its rotating mass (power output) to be between 200 and 250 MW and a switchable load of 10%
|Country||Frequency Control||Voltage Management||Black Start|
|Primary frequency control||Secondary frequency control||Tertiary frequency control||Reactive power absorbption/injection||Restart the power system after a black-out|
|California (USA)||Description: Not mandatory service. The beneficiaries are decided through a competitive market||Description: Must be available in a 10 min window and must be maintained for a minimum of 2 h.||Description: It can be synchronous tertiary frequency regulation or non-synchronized reserve||Description: Provided by all Generators with PF between 0.90 and 0.95.||Description: CAISO jointly with Participating Transmission Owner analyse the fulfillment of reliability in order to define the quantity and location of Generation units need to provide black-start|
|Procurement of necessary volume of service for each control area as a percentage of the total predicted load. Typical values: 5–12% of the demand.||Procurement: Similar to primary frequency. Typical value: 3% of the maximum demand||−||Procurement of additional reactive power needed through bilateral agreements, based on real-time needs. The remuneration reflects the opportunity cost of the production lost depending on capacity and use.||Procurement: Generating units can propose a bilateral agreement to CAISO (normally for a year) for compensating the costs plus additional benefits|
|Argentina||Description: Response time varies depending on the technology (e.g., thermal generators up to 30 s, hydro up to 60 s). The service should be provided for about 10 min.||Description: A generating unit should have a ramping capability of more than 30 MW/min. Response time should be 10–15 min, none specification for the total duration.||−||Description: The capacity of required reactive power is calculated by TSO. An instantaneous response and permanent supply of up to 90% of this reactive power for 20 min must be feasible.||Description: After a partial or total system collapse, each operator sets a range of actions that must be respected by some users|
|Procurement: Mandatory service for all system generators, who are responsible to maintain the frequency in their dispatched area. They are not compensated for this service.||Procurement: Voluntary service. In case of Hyrdo, the system recognizes the cost of the service provided as the energy price that they offer, while in thermal generator is this payment is proportional to the hydro price.||−||Procurement: Provided by generators and transmission companies. Penalties to generators, distributors and large consumers for no keeping their PF under the regulated range.||Procurement: Mandatory service, but not specific requirements for response time, duration or compensation schemes.|
|New Zealand||Description: Instantaneous reserve is generating capacity, or interruptible load, available to operate automatically. This service is required to stop the resulting fall in frequency. Over-frequency reserve is provided by generating units that can be armed when required and automatically disconnected from the power system due to a sudden rise in system frequency. Back-up Single Frequency Keeping (Back-Up SFK)||Description: Multiple Frequency Keeping. This service is provided by one or more generators capable of quickly varying their output in response to instructions from the System Operator. |
Back-up single frequency. Only takes effect if the system operator cannot deliver multiple frequency keeping.
|−||Description: Voltage support is provided by generating units or static equipment capable of producing or absorbing reactive power||Description: Process of system restoration in the unlikely event of an island-wide black-out|
|Procurement: Instantaneous reserve, 30 min clearing market. |
Over-frequency reserve, bilateral contracts. Back-Up SFK: monthly availability fee
|Procurement: Multiple Frequency Keeping 30 min clearing market |
Back-up Single frequency. Bilateral contracts with tendering process
|−||Procurement: Voltage support is procured on a firm quantity procurement basis (via a monthly availability fee and/or a single event fee for a specified MVAr availability).||Procurement: Bilateral contracts with tendering process|
|Australia||Description: Primary frequency control is designed to act within several seconds (and generally up to approximately 60 s) to provide a proportional response to measured changes in local frequency and contain deviations.||Description: Increase or reduction of active power, in response to a remote signal, to restore the system’s frequency back to 50 Hz.||Description: Because the NEM has a relatively short dispatch interval of five minutes, tertiary frequency control, which acts to relieve sources of primary and secondary frequency control, is effectively achieved through the central dispatch process which re-balances the system every five minutes.||Description: AEMO operates the power system to keep voltage level across connection points in the transmission network within a target range. This involves the coordination of available reactive power reserves provided by the network assets and generating units. (Reactive power supply. PF between 0.9 inductive and 0.93 capacitive)||Description: Provided in case of contingency, after a major supply disruption or when power system restart is required.|
|Procurement: Fast and slow contingency frequency control ancillary services (FCAS) Markets. Competitive auctions. Capacity and use.||Procurement: Managed in the NEM through the use of regulation and delayed contingency FCAS services. Competitive auctions. Real-time dispatch.||Procurement: Competitive auctions. Real-time dispatch.||Procurement: Bilateral Contracts||Procurement: Bilateral contracts on each zone of the power system. The service is paid on the basis of availability.|
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|CAISO||Maximum flexible ramp up and down requirements are defined as the 2.5% and the 97.5% percentile of net load change |
Intra-day 15–min market: −1200 MW downwards and 1800 MW upwards;
Intra-day 5–min market: −300 MW and 500 MW in both directions
|MISO||Depends on the sum of the forecasted change in net load and an additional amount of ramp up/down (575 MW for now) |
Highest hourly average real-time requirement: 1554 MW (ramp up) and 1614 MW (ramp down)
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